August 11, 2021 - 10-Q: Quarterly report pursuant to Section 13 or 15(d)

Form: 10-Q

Documents

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________

FORM 10-Q

________________________________

(Mark One)

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

For the quarterly period ended June 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 July 31, 2021, there were outstanding 58,585,062 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
June 30, 2021 and December 31, 2020	2
Condensed Consolidated Statements of Operations
Three and Six Months Ended June 30, 2021 and 2020	3
Condensed Consolidated Statements of Shareholders’ Equity
Three and Six Months Ended June 30, 2021 and 2020	4
Condensed Consolidated Statements of Cash Flows
Six Months Ended June 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	38
ITEM 4. CONTROLS AND PROCEDURES	38
PART II. OTHER INFORMATION	39
ITEM 1. LEGAL PROCEEDINGS	39
ITEM 1A. RISK FACTORS	39
ITEM 6. EXHIBITS	39

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

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PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)



	As of June 30, 2021		As of December 31, 2020
ASSETS	(in thousands)
Current assets:
Cash and cash equivalents	$	22,884	$	47,853
Restricted cash		83		86
Receivables:
Trade		28,801		—
Accounts with joint venture owners, net of allowance of $0.0 million in both periods presented		77		3,587
Other		24		4,331
Crude oil inventory		3,107		3,906
Prepayments and other		4,348		4,215
Total current assets		59,324		63,978

Crude oil and natural gas properties, equipment and other - successful efforts method, net		74,202		37,036
Other noncurrent assets:
Restricted cash		1,752		925
Value added tax and other receivables, net of allowance of $5.6 million and $2.3 million, respectively		5,618		4,271
Right of use operating lease assets		16,259		22,569
Deferred tax assets		1,511		—
Abandonment funding		22,837		12,453
Total assets	$	181,503	$	141,232
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	5,545	$	16,690
Accounts with joint venture owners		2,013		4,945
Accrued liabilities and other		34,980		17,184
Operating lease liabilities - current portion		13,288		12,890
Foreign income taxes payable		12,533		860
Current liabilities - discontinued operations		7		7
Total current liabilities		68,366		52,576
Asset retirement obligations		32,633		17,334
Operating lease liabilities - net of current portion		2,968		9,671
Other long-term liabilities		—		193
Total liabilities		103,967		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, 69,420,003 and 67,897,530 shares issued, 58,585,062 and 57,531,154 shares outstanding, respectively		6,942		6,790
Additional paid-in capital		75,778		74,437
Less treasury stock, 10,834,941 and 10,366,376 shares, respectively, at cost		(43,589)		(42,421)
Retained earnings		38,405		22,652
Total shareholders' equity		77,536		61,458
Total liabilities and shareholders' equity	$	181,503	$	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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(in thousands, except per share amounts)
Revenues:
Crude oil and natural gas sales	$	47,023	$	17,974	$	86,797	$	36,363
Operating costs and expenses:
Production expense		16,419		12,126		32,552		21,875
Exploration expense		665		—		807		—
Depreciation, depletion and amortization		5,810		2,801		9,958		5,904
Impairment of proved crude oil and natural gas properties		—		—		—		30,625
General and administrative expense		4,734		3,019		9,281		3,773
Bad debt expense and other		395		179		496		989
Total operating costs and expenses		28,023		18,125		53,094		63,166
Other operating expense, net		(126)		(815)		(486)		(846)
Operating income (loss)		18,874		(966)		33,217		(27,649)
Other income (expense):
Derivative instruments gain (loss), net		(9,969)		(756)		(15,923)		6,583
Interest income, net		1		11		6		127
Other, net		(164)		47		4,416		16
Total other income (expense), net		(10,132)		(698)		(11,501)		6,726
Income (loss) from continuing operations before income taxes		8,742		(1,664)		21,716		(20,923)
Income tax expense (benefit)		2,825		(2,249)		5,911		31,229
Income (loss) from continuing operations		5,917		585		15,805		(52,152)
Income (loss) from discontinued operations, net of tax		(33)		11		(52)		(52)
Net income (loss)	$	5,884	$	596	$	15,753	$	(52,204)

Basic net income (loss) per share:
Income (loss) from continuing operations	$	0.10	$	0.01	$	0.27	$	(0.90)
Loss from discontinued operations, net of tax		0.00		0.00		0.00		0.00
Net income (loss) per share	$	0.10	$	0.01	$	0.27	$	(0.90)
Basic weighted average shares outstanding		58,072		57,456		57,855		57,716
Diluted net income (loss) per share:
Income (loss) from continuing operations	$	0.10	$	0.01	$	0.27	$	(0.90)
Loss from discontinued operations, net of tax		0.00		0.00		0.00		0.00
Net income (loss) per share	$	0.10	$	0.01	$	0.27	$	(0.90)
Diluted weighted average shares outstanding		58,574		57,594		58,527		57,716

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


	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

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)


	Six Months Ended June 30,
	2021		2020
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	15,753	$	(52,204)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations		52		52
Depreciation, depletion and amortization		9,958		5,904
Bargain purchase gain		(7,651)		—
Impairment of proved crude oil and natural gas properties		—		30,625
Other amortization		—		121
Deferred taxes		(1,511)		32,271
Unrealized foreign exchange gain		(308)		(19)
Stock-based compensation		2,073		(1,849)
Cash settlements paid on exercised stock appreciation rights		(2,933)		—
Derivative instruments (gain) loss, net		15,923		(6,583)
Cash settlements received (paid) on matured derivative contracts, net		(6,003)		7,216
Bad debt expense and other		496		989
Other operating loss, net		486		46
Operational expenses associated with equipment and other		521		1,077
Change in operating assets and liabilities:
Trade receivables		(17,645)		4,814
Accounts with joint venture owners		642		11,783
Other receivables		(131)		(857)
Crude oil inventory		3,508		219
Prepayments and other		(8,622)		(779)
Value added tax and other receivables		(500)		(695)
Accounts payable		(10,597)		(5,819)
Foreign income taxes receivable/payable		11,673		(2,386)
Accrued liabilities and other		8,028		(3,333)
Net cash provided by continuing operating activities		13,212		20,593
Net cash used in discontinued operating activities		(52)		(354)
Net cash provided by operating activities		13,160		20,239
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures		(4,301)		(20,097)
Acquisition of crude oil and natural gas properties		(22,505)		—
Net cash used in continuing investing activities		(26,806)		(20,097)
Net cash used in discontinued investing activities		—		—
Net cash used in investing activities		(26,806)		(20,097)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock		1,053		—
Treasury shares		(1,168)		(990)
Net cash used in continuing financing activities		(115)		(990)
Net cash used in discontinued financing activities		—		—
Net cash used in financing activities		(115)		(990)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		(13,761)		(848)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD		61,317		59,124
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	47,556	$	58,276

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)


	Six Months Ended June 30,
	2021		2020
	(in thousands)
Supplemental disclosure of cash flow information:
Income taxes paid in-kind with crude oil	$	—	$	1,855
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	1,244	$	3,932
Recognition of right-of-use operating lease assets and liabilities	$	—	$	565
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 to phase out a portion of the prior production cuts.

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. Crude oil prices improved by June 30, 2021, and therefore no additional charges or impairments were required in the three months and six months ended June 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 June 30, 2021 and 2020 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at June 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 June 30,
	2021		2020
	(in thousands)
Cash and cash equivalents	$	22,884	$	44,841
Restricted cash - current		83		1,090
Restricted cash - non-current		1,752		925
Abandonment funding		22,837		11,420
Total cash, cash equivalents and restricted cash	$	47,556	$	58,276

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 we requested establishment of such account, the Central Bank did not comply with our requests until February 2021. As a result, we were 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 is working with Citibank to complete the documentation required to open the account. Amendment No. 5 to the Etame Marin block PSC also 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 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, and it has obtained credit enhancements from some parties in the form of parental guarantees or letters of credit. 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 June 30, 2021 and December 31, 2020, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $13.5 million ($9.3 million, net to VAALCO) and $13.4 million ($4.5 million, net to VAALCO), respectively. The exchange rate was XAF 552.2 = $1.00 and XAF 534.8 = $1.00 at June 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.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021			2020	2021		2020
	(in thousands)
Allowance for bad debt
Balance at beginning of period	$	(5,092)	$	(1,725)	$	(2,273)	$	(1,508)
Bad debt charge		(395)		(179)		(496)		(989)

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Adjustment associated with reversal of allowance on Mutamba receivable		—		—		—		593
Adjustment associated with Sasol Acquisition		—		—		(2,879)		—
Foreign currency gain (loss)		(88)		—		73		—
Balance at end of period	$	(5,575)	$	(1,904)	$	(5,575)	$	(1,904)

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.

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 six months ended June 30, 2021 and 2020.

As of June 30, 2021

Balance Sheet Line

Level 1

Level 2

Level 3

Total

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		(in thousands)
Liabilities
SARs liability	Accrued liabilities	$	—	$	1,181	$	—	$	1,181
Derivative liability - crude oil swaps	Accrued liabilities		—		9,920		—		9,920
		$	—	$	11,101	$	—	$	11,101

		As of December 31, 2020
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Liabilities
SARs liability	Accrued liabilities	$	—	$	2,289	$	—	$	2,289
SARs liability	Other long-term liabilities		—		193		—		193
		$	—	$	2,482	$	—	$	2,482

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

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

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

Impairment – The Company reviews the crude oil and natural gas producing properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil and natural gas leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and in Block P in Equatorial Guinea. See Note 7 for further discussion.

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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, while accretion escalates over the lives of the assets to reach the settlement value. See Note 12 for disclosures regarding the asset retirement obligations. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. 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. 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. We also record 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 allocation is originally produced to the time the allocation is actually lifted.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit

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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.

In March 2020, the FASB issued ASU No. 2020-03 - Codification Improvements to Financial Instruments (“ASU 2020-03”). ASU 2020-03 improves and clarifies various financial instruments topics, including the CECL standard. ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. The amendments in ASU 2020-03 have different effective dates. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.

Adopted

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

3. ACQUISITIONS AND DISPOSITIONS

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

On February 25, 2021, VAALCO Gabon S.A. completed the acquisition of Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the SPA. The effective date of the transaction was July 1, 2020. Prior to the Sasol Acquisition, the Company owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased the Company’s working interest to 58.8%, almost doubling the Company’s total production and reserves. As a result of the Sasol Acquisition, the net portion of production and costs relating to the Company’s Etame operations increased from 31.1% to 58.8%. Reserves, production and financial

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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 “Total revenues” in the condensed consolidated statement of operations of $9.4 million for the six months ended June 30, 2021 and $1.2 million increase to “Net income” in the condensed consolidated statements of operations for the six months ended June 30, 2021, respectively.

The unaudited pro forma results presented below have been prepared to give the effect to the Sasol Acquisition discussed above on the Company’s results of operations for three and six months ended June 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 June 30,				Six Months Ended June 30,
	2021		2020		2021			2020
	(in thousands)
Pro forma (unaudited)
Crude oil and natural gas sales	$	47,023	$	34,034	$	104,570		$	68,854
Operating income (loss)		18,874		1,270		43,899			(20,231)
Net income (loss)		5,884		1,703		17,620	(a)		(45,452)	(b)

Basic net income (loss) per share:
Income (loss) from continuing operations	$	0.10	$	0.03	$	0.30		$	(0.79)
Loss from discontinued operations, net of tax		0.00		0.00		0.00			0.00
Net income (loss) per share	$	0.10	$	0.03	$	0.30		$	(0.79)
Basic weighted average shares outstanding		58,072		57,456		57,855			57,716
Diluted net income (loss) per share:
Income (loss) from continuing operations	$	0.10	$	0.03	$	0.30		$	(0.79)
Loss from discontinued operations, net of tax		0.00		0.00		0.00			0.00
Net income (loss) per share	$	0.10	$	0.03	$	0.30		$	(0.79)
Diluted weighted average shares outstanding		58,574		57,594		58,527			57,716

________________

(a)The pro forma net income for the six months ended June 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 six months ended June 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 six months ended June 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.

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


	Three Months Ended June 30, 2021
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	47,023	$	—	$	—	$	47,023
Depreciation, depletion and amortization		5,786		—		24		5,810

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Operating income (loss)	23,419	(102)	(4,443)	18,874
Derivative instruments loss, net	—	—	(9,969)	(9,969)
Income tax expense	2,721	—	104	2,825
Additions to crude oil and natural gas properties and equipment – accrual	1,782	—	—	1,782


	Six Months Ended June 30, 2021
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	86,797	$	—	$	—	$	86,797
Depreciation, depletion and amortization		9,907		—		51		9,958
Operating income (loss)		42,099		(234)		(8,648)		33,217
Derivative instruments loss, net		—		—		(15,923)		(15,923)
Other, net		7,525		(1)		(3,108)		4,416
Income tax expense (benefit)		7,960		1		(2,050)		5,911
Additions to crude oil and natural gas properties and equipment – accrual		4,297		—		—		4,297


	Three Months Ended June 30, 2020
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	17,974	$	—	$	—	$	17,974
Depreciation, depletion and amortization		2,772		—		29		2,801
Other operating expense, net		(815)		—		—		(815)
Operating income (loss)		1,704		(69)		(2,601)		(966)
Derivative instruments loss, net		—		—		(756)		(756)
Income tax benefit		(273)		—		(1,976)		(2,249)
Additions to crude oil and natural gas properties and equipment – accrual		1,190		—		—		1,190



	Six Months Ended June 30, 2020
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	36,363	$	—	$	—	$	36,363
Depreciation, depletion and amortization		5,844		—		60		5,904
Impairment of proved crude oil and natural gas properties		30,625		—		—		30,625
Bad debt expense and other		989		—		—		989
Other operating expense, net		(846)		—		—		(846)
Operating loss		(24,579)		(194)		(2,876)		(27,649)
Derivative instruments gain, net		—		—		6,583		6,583
Income tax expense		21,766		—		9,463		31,229
Additions to crude oil and natural gas properties and equipment – accrual		10,611		—		—		10,611



(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Long-lived assets from continuing operations:
As of June 30, 2021	$	64,049	$	10,000	$	153	$	74,202
As of December 31, 2020	$	26,832	$	10,000	$	204	$	37,036

(in thousands)

Gabon

Equatorial Guinea

Corporate and Other

Total

Total assets from continuing operations:

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As of June 30, 2021		$	150,538		$	10,299		$	20,666		$	181,503
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 six months ended June 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 June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
	(in thousands)
Net income (loss) (numerator):
Income (loss) from continuing operations	$	5,917	$	585	$	15,805	$	(52,152)
Income from continuing operations attributable to unvested shares		(99)		(3)		(269)		—
Numerator for basic		5,818		582		15,536		(52,152)
(Income) loss from continuing operations attributable to unvested shares		—		—		—		—
Numerator for dilutive	$	5,818	$	582	$	15,536	$	(52,152)

Income (loss) from discontinued operations, net of tax	$	(33)	$	11	$	(52)	$	(52)
(Income) loss from discontinued operations attributable to unvested shares		1		—		1		—
Numerator for basic		(32)		11		(51)		(52)
(Income) loss from discontinued operations attributable to unvested shares		—		—		—		—
Numerator for dilutive	$	(32)	$	11	$	(51)	$	(52)

Net income (loss)	$	5,884	$	596	$	15,753	$	(52,204)
Net income attributable to unvested shares		(98)		(3)		(268)		—
Numerator for basic		5,786		593		15,485		(52,204)
Net (income) loss attributable to unvested shares		—		—		—		—
Numerator for dilutive	$	5,786	$	593	$	15,485	$	(52,204)

Weighted average shares (denominator):
Basic weighted average shares outstanding		58,072		57,456		57,855		57,716
Effect of dilutive securities		502		138		672		—
Diluted weighted average shares outstanding		58,574		57,594		58,527		57,716
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		377		1,793		386		3,051

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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. 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. As of June 30, 2021, the foreign income taxes payable attributable to this obligation was $12.5 million. 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenue from customer contracts:	(in thousands)
Sales under the COSPA	$	50,808	$	18,816	$	94,637	$	39,260
Other items reported in revenue not associated with customer contracts:
Gabonese government share of Profit Oil taken in-kind		—		1,855		—		1,855
Carried interest recoupment		2,332		108		4,154		993
Royalties		(6,117)		(2,805)		(11,994)		(5,745)
Total revenue, net	$	47,023	$	17,974	$	86,797	$	36,363

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 June 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	$	477,908	$	441,879
Work-in-progress		1,172		169
Undeveloped acreage		23,735		21,476
Equipment and other		16,338		9,276
		519,153		472,800
Accumulated depreciation, depletion, amortization and impairment		(444,951)		(435,764)
Net crude oil and natural gas properties, equipment and other	$	74,202	$	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 six months ended June 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 second quarter of 2021 compared to the first quarter of 2021, and that the Company incurred no significant capital expenditures in the period related to the fields in the Etame Marin block.

There was no triggering event in the second 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 second quarter of 2020 compared to the first quarter of 2020, and that the Company incurred no significant capital expenditures in the period related to the fields in 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, Avouma, Ebouri, Southeast Etame and North Tchibala fields were less than the book values for these fields resulting in the Company recording a $30.6 million impairment loss to write down the Company’s investment in each field to their 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 June 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, 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 June 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 expense, net” line item of the condensed consolidated statements of operations but were not material for the three and six months ended June 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 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,

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

Settlement Period

Type of Contract

Index

Barrels

Weighted Average Price

July 2021 to January 2022

Swaps

Dated Brent

351,254

53.10

July 2021 to October 2021

Swaps

Dated Brent

377,869

66.13

729,123

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 June 30,				Six Months Ended June 30,
Derivative Item	Statement of Operations Line	2021		2020		2021		2020
		(in thousands)
Crude oil swaps	Realized gain (loss) - contract settlements	$	(4,293)	$	6,498	$	(6,003)	$	7,216
	Unrealized loss		(5,676)		(7,254)		(9,920)		(633)
	Derivative instruments gain (loss), net	$	(9,969)	$	(756)	$	(15,923)	$	6,583

9. ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:


	As of June 30, 2021		As of December 31, 2020
	(in thousands)
Accrued accounts payable invoices	$	8,814	$	4,070
Gabon DMO, PID and PIH obligations		9,535		3,960
Derivative liability - crude oil swaps		9,920		—
Capital expenditures		1,108		435
Stock appreciation rights – current portion		1,181		2,289
Accrued wages and other compensation		2,450		2,108
Other		1,972		4,322
Total accrued liabilities and other	$	34,980	$	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-refundable. The abandonment estimate used for this purpose is approximately

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$61.8 million ($36.4 million net to VAALCO) on an undiscounted basis. Through June 30, 2021, $38.8 million ($22.8 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 June 30, 2021, the foreign currency loss associated with the abandonment funding account was not material. During the six months ended June 30, 2021, the Company recorded $0.6 million 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 $0.2 million as of June 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 $40.4 million in remaining gross minimum obligations as of June 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.

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. 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.

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

The FPSO, 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.

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Lease cost:	(in thousands)
Operating lease cost	$	4,490	$	4,335	$	8,880	$	8,525
Short-term lease cost		449		(581)		1,243		451
Variable lease cost		1,627		2,138		3,061		4,064
Total lease expense		6,566		5,892		13,184		13,040
Lease costs capitalized		—		178		—		3,459
Total lease costs	$	6,566	$	6,070	$	13,184	$	16,499

Other information:
Cash paid for amounts included in the measurement of lease liabilities:					2021		2020
Operating cash flows attributable to operating leases					$	11,863	$	13,966
Weighted-average remaining lease term						1.25 years		2.2 years
Weighted-average discount rate						6.09%		6.13%

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 June 30,

Six Months Ended June 30,

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	2021		2020		2021		2020
	(in thousands)
Production expense	$	3,852	$	1,814	$	6,501	$	4,019
General and administrative expense		47		49		96		98
Lease costs billed to the joint venture owners		2,667		4,148		6,587		11,221
Total lease expense		6,566		6,011		13,184		15,338
Lease costs capitalized		—		59		—		1,161
Total lease costs	$	6,566	$	6,070	$	13,184	$	16,499

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


	Lease Obligation
Year	(in thousands)
2021	$	6,978
2022		9,685
2023		179
		16,842
Less: imputed interest		586
Total lease liabilities	$	16,256

Under the joint operating agreements, other joint venture owners are obligated to fund $6.9 million of the $16.8 million in future lease liabilities.

12. ASSET RETIREMENT OBLIGATIONS

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


(in thousands)	As of June 30, 2021		As of December 31, 2020
Beginning balance	$	17,334	$	15,844
Accretion		735		893
Additions		14,564		359
Revisions		—		238
Ending balance	$	32,633	$	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 June 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 on the date the restricted stock awards vest is net of shares withheld to meet applicable tax withholding requirements. 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

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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 June 30, 2021, 7,555,600 shares were available for future grants under the 2020 Plan.

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

As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the three and six months ended June 30, 2021, the Company settled in cash $2.9 million for stock appreciation rights and received $1.1 million for stock option exercises. During the six months ended June 30, 2020, the Company did not settle any stock-based compensation. Because the Company does not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(in thousands)
Stock-based compensation - equity awards	$	117	$	60	$	440	$	205
Stock-based compensation - liability awards		397		660		1,633		(2,054)
Total stock-based compensation	$	514	$	720	$	2,073	$	(1,849)

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 option award, options with respect to one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $3.61 per share; 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 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 six months ended June 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 paid cash dividends and does not anticipate paying cash dividends on the common stock in the foreseeable future, no expected dividend yield was input to the Black-Scholes or Monte Carlo models. During the six months ended June 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 model in 2020.


	Six Months Ended June 30,
	2021		2020
Weighted average exercise price - ($/share)	$	3.14	$	1.23
Expected life in years		6.0		6.0

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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 six months ended June 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 June 30, 2021	359	$	1.96	9.26	$	462
Exercisable at June 30, 2021	74	$	1.23	8.99	$	149

Stock option activity associated with the Black-Scholes model for the six months ended June 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	(980)		1.07
Unvested shares forfeited	(60)		2.33
Vested shares expired	—		—
Outstanding at June 30, 2021	764	$	1.70	1.73	$	1,181
Exercisable at June 30, 2021	663	$	1.61	1.59	$	1,087

During the six months ended June 30, 2021, 400,431 shares were added to treasury as a result of tax withholding on options exercised. During the six months ended June 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 June 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 June 30, 2021	755	$	2.36

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During the six months ended June 30, 2021, 68,134 shares were added to treasury as a result of tax withholding on the vesting of restricted shares. During the six months ended June 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 six months ended June 30, 2021 and 2020, the Company did not grant SARs to employees or directors.

SAR activity for the six months ended June 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	(2,213)		1.18
Unvested SARs forfeited	(122)		2.33
Vested SARs expired	—		—
Outstanding at June 30, 2021	605	$	1.68	2.36	$	949
Exercisable at June 30, 2021	431	$	1.51	2.20	$	750

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.

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
U.S. Federal:	(in thousands)
Current	$	—	$	72	$	—	$	(525)
Deferred		104		(2,048)		(2,049)		9,988
Foreign:
Current		6,148		1,046		9,583		(517)
Deferred		(3,427)		(1,319)		(1,623)		22,283
Total	$	2,825	$	(2,249)	$	5,911	$	31,229

The Company’s effective tax rate for the six months ended June 30, 2021 and 2020, excluding the impact of discrete items, was 40.6% and (56%), respectively. For the six months ended June 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. 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. The total change in valuation allowances for the six months ended June 30, 2021 was $(7.0) million. For the three months ended June 30, 2021, the current tax expense of $6.1 million includes a $1.0 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 $5.1 million for the period. For the six months ended June 30, 2021, the current tax expense of $9.6 million includes a $1.5 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 $8.1 million for the period.

As of June 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 the sharp decline in the global demand for crude oil, which resulted in a significant global oversupply of crude oil and steep decline in crude oil prices, potential difficulties in obtaining additional liquidity when and if needed, disruptions in global supply chains, quarantines of our workforce or workforce reductions and other matters related to the pandemic;

the impact of 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;

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

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

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

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

the impact of competition;

our ability to identify and complete complementary opportunistic acquisitions;

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

weather conditions;

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

currency exchange rates and regulations;

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

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

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

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

our ability to find a replacement for the floating, production, storage and offloading vessel (“FPSO”) or to renew the FPSO charter;

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

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

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

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our ability to enter into new customer contracts;

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. In the second quarter of 2021, crude oil and natural gas prices have improved, although the recent surge in mutated strains of COVID-19 may impact prices in the future. Despite these challenges, we remain committed to generating long-term value for our stockholders by focusing on exploration and development of existing properties, adding value with accretive acquisitions, controlling costs and optimizing production.

RECENT DEVELOPMENTS

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

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

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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. We currently have crude oil commodity swap agreements for a total of 351,254 barrels at a Dated Brent weighted average price of $53.10 per barrel for the period from and including July 2021 through January 2022 as well as 377,869 barrels at a Dated Brent weighted average price of $66.13 per barrel for the period from July 2021 through October 2021 to mitigate the effects of potential future price declines. See Note 8 for further discussion. 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.

We will consider entering into additional commodity derivative instruments from time to time. However, there can be no assurance when, or upon what terms, we may enter into any future commodity derivative instruments.

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. We expect the seismic data to enhance sub-surface imaging by merging legacy data with newly acquired seismic allowing for the first continuous 3-D seismic over the entire block. The processing of the seismic data began in January 2021, and we expect all the data to be fully processed and analyzed by the first quarter of 2022. The seismic data will be used to optimize and de-risk future drilling locations and potentially identify new drilling locations. We plan to commence the next drilling campaign at Etame in late 2021 or early 2022 with two development wells and two appraisal wells at an estimated cost of $115.0 million to $125.0 million gross, or $73.0 million to $79.0 million, net to VAALCO’s 63.6% participating interest. The locations of these wells will be determined in conjunction with the new seismic processing and interpretation.

In June 2021, in conjunction with our 2021/2022 drilling program, we entered into a contract with an affiliate of Borr Drilling Limited to drill a minimum of three wells with options to drill additional wells. The contract provides, among other things, that the drilling rig can be on location as early as December 2021, with the exact timing dependent on other commitments related to the rig.

We are currently a party to an FPSO charter for the storage of all of the crude oil that we produce. This contract will expire in September 2022. Our options include securing a new storage vessel, either under a charter agreement or a purchase, purchasing the vessel under the current FPSO charter pursuant to an option in the charter contract or extending the charter agreement for the current FPSO. Execution of any of these options requires significant lead time and may require a capital investment due to the specialized nature of such vessels. We are currently evaluating our alternatives so that we will be in position to have an alternative in place when the current charter expires.

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%, almost doubling our total production and reserves. As a result of the Sasol Acquisition, the

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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 “Total revenues” in the condensed consolidated statement of operations of $9.4 million for six months ended June 30, 2021 and a $1.2 million increase to “Net income” in the condensed consolidated statement of operations for the six months ended June 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, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of a consortium of companies. As of June 30, 2021, production operations in the Etame Marin block included eleven platform wells, plus three subsea wells across all fields 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 June 30, 2021 and 2020, production from the block was 1,426 MBbls (730 MBbls net) and 1,822 MBbls (492 MBbls net), respectively, as discussed below in “Results of Operations”. During the six months ended June 30, 2021 and 2020, production from the Etame Marin block was 2,679 MBbls (1,196 MBbls net) and 3,487 MBbls (942 MBbls net), respectively, as discussed below in “Results of Operations”.

Equatorial Guinea

VAALCO’s working interest will increase to 45.9% once the EG MMH approves a new amendment to the production sharing contract. As of June 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. 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.

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 six months ended June 30, 2021 and 2020 are as follows:


	Six Months Ended June 30,
	2021		2020		Increase (Decrease) in 2021 over 2020
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	26,856	$	17,646	$	9,210
Net change in operating assets and liabilities		(13,644)		2,947		(16,591)
Net cash provided by continuing operating activities		13,212		20,593		(7,381)
Net cash used in discontinued operating activities		(52)		(354)		302

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Net cash provided by operating activities		13,160		20,239		(7,079)

Net cash used in investing activities		(26,806)		(20,097)		(6,709)

Net cash used in continuing financing activities		(115)		(990)		875
Net cash used in financing activities		(115)		(990)		875
Net change in cash, cash equivalents and restricted cash	$	(13,761)	$	(848)	$	(12,913)

The $9.2 million increase in net cash provided by our operating activities before changes in operating assets and liabilities for the six months ended June 30, 2021 compared to the same period of 2020, was mainly due to higher crude oil prices in 2021 partially offset by higher operating costs and expenses as discussed below in “Results of Operations”. The net decrease in operating assets and liabilities of $16.6 million for the six months ended June 30, 2021 compared to the same period of 2020 was primarily related to increases in accounts receivable and accounts with joint venture owners partially offset by increases in foreign income taxes payable.

Net cash used in investing activities during the six months ended June 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 $4.3 million for property and equipment primarily related to equipment and enhancements as well as expenditures related the next drilling program as discussed in “Recent Operational Updates” above. During the six months ended June 30, 2020, we incurred on a cash basis $20.1 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 six months ended June 30, 2021 included $1.2 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 $1.1 million in proceeds from options exercised. Net cash used in financing activities during the six months ended June 30, 2020 included $1.0 million for treasury stock purchases primarily made under the Company’s stock repurchase plan.

Capital Expenditures

During the six months ended June 30, 2021, we incurred accrual basis capital expenditures of $4.3 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 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 $115.0 million to $125.0 million gross, or $73.0 million to $79.0 million, net to VAALCO’s 63.6% participating interest. In April 2021, we purchased a workover unit to have on site for approximately $1.9 million for future maintenance work.

We are currently evaluating our alternatives to the current FPSO charter that will expire in September 2022. We expect that any of these alternatives will involve significant capital expenditures.

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.

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.

Capital Resources

Cash on Hand

At June 30, 2021, we had unrestricted cash of $22.9 million. The unrestricted cash balance includes $2.0 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 in January 2022. Pricing under the contract is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

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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 June 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.

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 September 2022. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities.

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.

RESULTS OF OPERATIONS

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

Net income for the three months ended June 30, 2021 of $5.9 million, compared to net income of $0.6 million for the same period of 2020. See discussion below for changes in revenue and expense.

Crude oil and natural gas revenues increased $29.0 million, or approximately 161.6%, during the three months ended June 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.


	Three Months Ended June 30,
	2021		2020		Increase/(Decrease)
	(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		642		631		11
Average crude oil sales price (per Bbl)	$	69.61	$	28.31	$	41.30

Net crude oil revenue	$	47,023	$	17,974	$	29,049

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Operating costs and expenses:
Production expense		16,419		12,126		4,293
Exploration expense		665		—		665
Depreciation, depletion and amortization		5,810		2,801		3,009
General and administrative expense		4,734		3,019		1,715
Bad debt expense		395		179		216
Total operating costs and expenses		28,023		18,125		9,898
Other operating income (expense), net		(126)		(815)		689
Operating income (loss)	$	18,874	$	(966)	$	19,840

The revenue changes in the three months ended June 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 June 30,
	2021		2020
Gabon net crude oil production (MBbls)		730		492
Gabon net crude oil sales (MBbls)		642		631

Average realized crude oil price ($/Bbl)	$	69.61	$	28.31
Average Dated Brent spot price* ($/Bbl)		68.98		29.70
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made two liftings during the three months ended June 30, 2021 and four liftings during the three months June 30, 2020. However, the total barrels lifted in the three months ended June 30, 2021 was more than the barrels lifted during the same period in 2020. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 133,704 barrels and 47,142 barrels at June 30, 2021 and 2020, respectively.

Production expenses increased $4.3 million, or approximately 35.4%, in the three months ended June 30, 2021 compared to the same period in 2020. The increase in expense was primarily related to higher FPSO charter, transportation and personnel costs partially offset by lower crude oil inventory costs. On a per barrel basis, production expense, excluding workover expense, for the three months ended June 30, 2021 increased to $25.02 per barrel from $19.31 per barrel for the three months ended June 30, 2020 primarily as a result of an increase in costs in 2021. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $0.8 million in higher costs related to the proactive measures taken in response to the pandemic for each of the three months ended June 30, 2021 and 2020.

Depreciation, depletion and amortization costs increased $3.0 million, or approximately 107.4% due to higher depletable costs associated with the Sasol Acquisition.

General and administrative expenses increased $1.7 million, or approximately 56.8% in the three months ended June 30, 2021 compared to the same period of 2020. The increase in expense was primarily related to additional severance costs associated with changes in key personnel.

Bad debt expense was higher between the three months ended June 30, 2021 and 2020 primarily due to bad debt expense associated with the VAT allowance.

Other operating expense, net for the three months ended June 30, 2021 decreased primarily due to an $0.8 million charge for the settlement of a joint venture audit during the same period of 2020.

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Derivative instruments gain (loss), net is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements. The $10.0 million and $0.8 million losses for the three months ended June 30, 2021 and 2020, respectively, are the result of the increases in the price of Dated Brent crude oil during both periods. Our current derivative instruments only cover a portion of our production through January 2022.

Other, net for the three months ended June 30, 2021 and June 30, 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 June 30, 2021 was $2.8 million of expense. This is comprised of $(3.3) million of deferred tax benefit and a current tax expense of $6.1 million. Income tax expense for the three months ended June 30, 2020 was a benefit of $2.2 million and included $(3.4) million of deferred tax benefit and a current tax expense of $1.2 million. For both the three months ended June 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.

Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020

Net income for the six months ended June 30, 2021 of $15.8 million, compared to net loss of $52.2 million for the same period of 2020. See the discussion below for changes in revenue and expense.

Crude oil and natural gas revenues increased $50.4 million, or approximately 138.7% during the six months ended June 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.


	Six Months Ended June 30,
	2021		2020		Increase/(Decrease)
	(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		1,261		925		336
Average crude oil sales price (per Bbl)	$	65.54	$	38.24	$	27.30

Net crude oil revenue	$	86,797	$	36,363	$	50,434

Operating costs and expenses:
Production expense		32,552		21,875		10,677
Exploration expense		807		—		807
Depreciation, depletion and amortization		9,958		5,904		4,054
Impairment of proved crude oil and natural gas properties		—		30,625		(30,625)
General and administrative expense		9,281		3,773		5,508
Bad debt expense		496		989		(493)
Total operating costs and expenses		53,094		63,166		(10,072)
Other operating expense, net		(486)		(846)		360
Operating income (loss)	$	33,217	$	(27,649)	$	60,866

The revenue changes in the six months ended June 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.


	Six Months Ended June 30,
	2021		2020
Gabon net crude oil production (MBbls)		1,196		942
Gabon net crude oil sales (MBbls)		1,261		925

Average realized crude oil price ($/Bbl)	$	65.54	$	38.24

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Average Dated Brent spot price* ($/Bbl)			64.95			40.23
*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 five liftings during the six months ended June 30, 2021 and six liftings during the six months June 30, 2020. However, the total barrels lifted in the six months ended June 30, 2021 was more than the barrels lifted during the same period in 2020. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 133,704 and 47,142 barrels at June 30, 2021 and 2020, respectively.

Production expenses increased $10.7 million, or approximately 48.8%, in the six months ended June 30, 2021 compared to the same period in 2020. The increase in expense was primarily related to higher crude oil inventory costs, personnel, transportation and FPSO charter costs partially offset by lower workovers. On a per barrel basis, production expense, excluding workover expense, for the six months ended June 30, 2021 increased to $25.52 per barrel from $20.61 per barrel for the six months ended June 30, 2020 primarily as a result of a natural decline in oil production. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $1.4 million and $0.8 million, respectively, in higher costs related to the proactive measures taken in response to the pandemic for the six months ended June 30, 2021 and 2020.

Depreciation, depletion and amortization costs increased $4.1 million, or approximately 68.7%, in the six months ended June 30, 2021 compared to the same period in 2020 due to higher depletable costs associated with the Sasol Acquisition.

General and administrative expenses increased $5.5 million, or approximately 146.0% in the six months ended June 30, 2021 compared to the same period of 2020. The increase in expense was primarily related to $3.7 million in SARs expense and $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 six months ended June 30, 2021 and 2020 primarily due to bad debt expense associated with the VAT allowance.

Other operating expense, net for the six months ended June 30, 2021 decreased by $0.4 million in expense. The $0.5 million balance for the six months ended June 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 six months ended June 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 $15.9 million loss for the six months ended June 30, 2021 is a result of the increase in the price of Dated Brent crude oil during the six months ended June 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 only cover a portion of our production through January 2022.

Other, net for the six months ended June 30, 2021 is primarily attributable to $5.5 million for the bargain purchase gain offset by $1.0 million for an acquisition success fee.

Income tax expense (benefit) for the six months ended June 30, 2021 was $5.9 million of expense. This is comprised of $(3.7) million of deferred tax benefit and a current tax expense of $9.6 million. Income tax expense for the six months ended June 30, 2020 was $31.2 million of expense. This is comprised of $32.1 million of deferred tax expense and a current tax benefit of $(1.0) million. The deferred income tax expense for the six months ended June 30, 2020 included a $42.8 million charge to increase the valuation allowances on U.S. and Gabonese deferred tax assets offset by a $(10.7) million deferred tax benefit. For both the six months ended June 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 OPEN

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 June 30,

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2021, we had net monetary assets of $8.6 million (XAF 4,723.8 million) (net to VAALCO) denominated in XAF. A 10% weakening of the CFA Franc relative to the U.S. dollar would have a $(0.8) million reduction in the value of these net assets. For the three and six months ended June 30, 2021, we had expenditures of approximately $5.8 million and $9.7 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 Open

Our major market risk exposure continues to be the prices received for our crude oil production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil and natural gas have been volatile and 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 642 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $3.2 million and $12.8 million decrease per quarter and annualized, respectively, in revenues and operating income and a $2.9 million and $11.5 million decrease per quarter and annualized in net income, respectively.

As of June 30, 2021, we had crude oil swaps outstanding. In the past, we have used derivative instruments as an economic hedge against declines in crude oil prices; however, such instruments were not designated as hedges for accounting purposes. Our derivative instruments only cover a portion of our production through January 2022. See Note 8 to our condensed consolidated financial statements for further discussion.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on their evaluation as of June 30, 2021, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective.

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 is currently voluntary through the date of this report. While modifications were made to the manner in which controls were performed, these changes did not have a material effect on our internal control over financial reporting, and there were no changes in our internal control over financial reporting that occurred during the three months ended June 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 secure a method of storing the crude oil we produce 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. Our options include securing a new storage vessel, either under a charter agreement or a purchase, purchasing the vessel under the current FPSO charter pursuant to an option in the charter contract or extending the charter agreement for the current FPSO. Execution of any of these options requires significant lead time and may require a capital investment due to the specialized nature of such vessels. To become operational, significant engineering studies, platform modifications, mooring and pipeline surveys as well as installation must be completed. If we are not able to timely secure an alternative method of storing the

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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.

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).
10.1*	Separation Agreement, by and between VAALCO Energy, Inc. and Cary Bounds, dated April 9, 2021 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 12, 2021 and incorporated herein by reference).
10.2*	Employment Agreement, by and between VAALCO Energy, Inc. and Michael G. Silver, effective as of May 2, 2021 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 28, 2021 and incorporated herein by reference).
10.3*	Employment Agreement, by and between VAALCO Energy, Inc. and George Maxwell, effective as of April 19, 2021 (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 12, 2021 and incorporated herein by reference).
10.4*	First Amendment to the VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 8, 2021 and incorporated herein by reference).
10.5*	Employment Agreement, effective as of June 21, 2021, by and between VAALCO Energy, Inc. and Ronald Bain (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 22, 2021 and incorporated herein by reference).
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.
‎

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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: August 11, 2021

(in thousands)