UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

~~________________________________~~

FORM 10-Q

~~________________________________~~

(Mark One)

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

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

For the quarterly period ended March 31, ~~2022~~2023

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

☐	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~~File Number 1-32167

~~________________________________~~

VAALCOEnergy,Inc.

(Exact name of registrant as specified in its charter)

~~________________________________~~

Delaware		76-0274813
~~Delaware~~(Stateorotherjurisdictionof incorporationororganization)	(I.R.S.Employer IdentificationNo.)

9800RichmondAvenue Suite 700 Houston, Texas	~~76-0274813~~77042
(~~State or other jurisdiction~~ Addressof ~~incorporation or organization)~~principalexecutiveoffices)		~~(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~~Registrant’s telephone number, including area code)

~~________________________________~~

Table of Contents

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 of 1934 during the past preceding 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 (§232.405 of this chapter) 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

☒

~~Large~~ Non‑accelerated filer

¨☐

~~Accelerated filer~~

~~Non~~-~~accelerated filer~~

Smaller reporting company

Emerging growth company

x☐

¨☐

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 Rule 12b-2 of the Exchange ~~Act Rule 12b-2)~~Act). Yes ¨☐ No x☒

As of ~~April 30, 2022,~~May 8, 2023 there were outstanding ~~58,902,069~~106,772,598 shares of common stock, $0.10 par value per share, of the registrant.


					*As of March 31, 2023*			*As of December 31, 2022*
	As of March 31, 2022		As of December 31, 2021		*(in thousands)*
ASSETS	(in thousands)
Current assets:
Cash and cash equivalents	$	18,939	$	48,675	$	52,119		$	37,205
Restricted cash		4,230		79		76			222
Receivables:
Trade, net		44,616		22,464		30,795			52,147
Accounts with joint venture owners, net of allowance of $0.0 million in both periods presented		3,764		345
Other, net		11,612		9,977
Accounts with joint venture owners, net of allowance for credit losses of $0.3 million in both periods presented						25			15,830
Foreign income taxes receivable						—			2,769
Other, net of allowance for credit losses of $3.5 and $0.0 million, respectively						67,157			68,519
Crude oil inventory		4,634		1,593		11,778			3,335
Prepayments and other		8,408		5,156		17,424			20,070
Total current assets		96,203		88,289		179,374			200,097

Crude oil and natural gas properties, equipment and other - successful efforts method, net		121,935		94,324		499,953			495,272
Other noncurrent assets:
Restricted cash		1,752		1,752		1,771			1,763
Value added tax and other receivables, net of allowance of $6.1 million and $5.7 million, respectively		5,692		5,536
Value added tax and other receivables, net of allowance of $9.0 million and $8.4 million, respectively						8,026			7,150
Right of use operating lease assets		6,872		10,227		2,211			2,777
Right of use finance lease assets		1,795		—		91,198			90,698
Deferred tax assets		50,296		39,978		33,430			35,432
Abandonment funding		21,369		21,808		6,268			20,586
Other long-term assets		2,596		1,176		1,752			1,866
Total assets	$	308,510	$	263,090	$	823,983		$	855,641
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	10,509	$	18,797	$	49,982		$	59,886
Accounts with joint venture owners		—		3,233		3,098			—
Accrued liabilities and other		91,409		49,444		80,707			91,392
Operating lease liabilities - current portion		6,429		9,642		2,040			2,314
Finance lease liabilities - current portion		341		—		6,907			7,811
Foreign income taxes payable		8,819		3,128		5,424			—
Current liabilities - discontinued operations		7		13		673			687
Total current liabilities		117,514		84,257		148,831			162,090
Asset retirement obligations		34,377		33,949		42,327			41,695
Operating lease liabilities - net of current portion		461		587		367			686
Finance lease liabilities - net of current portion		1,411		-		80,470			78,248
Deferred tax liabilities						79,854			81,223
Other long-term liabilities						16,959			25,594
Total liabilities		153,763		118,793		368,808			389,536
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, $25 par value; 500,000 shares authorized, none issued		—		—
Common stock, $0.10 par value; 100,000,000 shares authorized, 69,862,217 and 69,562,774 shares issued, 58,858,901 and 58,623,451 shares outstanding, respectively		6,986		6,956
Preferred stock, $25 par value; 500,000 shares authorized, none issued						—			—
Common stock, $0.10 par value; 160,000,000 shares authorized, 120,116,106 and 119,482,680 shares issued, 107,318,214 and 107,852,857 shares outstanding, respectively						12,012			11,948
Additional paid-in capital		77,272		76,700		354,499			353,606
Less treasury stock, 11,003,316 and 10,939,323 shares, respectively, at cost		(44,234)		(43,847)
Accumulated other comprehensive income						1,054			1,179
Less treasury stock, 12,797,892 and 11,629,823 shares, respectively, at cost						(53,029	)		(47,652	)
Retained earnings		114,723		104,488		140,639			147,024
Total shareholders' equity		154,747		144,297		455,175			466,105
Total liabilities and shareholders' equity	$	308,510	$	263,090	$	823,983		$	855,641

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Unaudited)

Three Months Ended March 31,
2022
2021
(in thousands, except per share amounts)
Revenues:
Crude oil and natural gas sales
$
68,656
$
39,774
Operating costs and expenses:
Production expense
18,360
16,133
Exploration expense
127
142
Depreciation, depletion and amortization
4,673
4,148
General and administrative expense
4,994
4,547
Bad debt expense and other
492
101
Total operating costs and expenses
28,646
25,071
Other operating expense, net
(5)
(360)
Operating income
40,005
14,343
Other income (expense):
Derivative instruments loss, net
(31,758)
(5,954)
Interest (expense) income, net
(3)
5
Other (expense) income, net
(696)
4,580
Total other expense, net
(32,457)
(1,369)
Income from continuing operations before income taxes
7,548
12,974
Income tax (benefit) expense
(4,628)
3,086
Income from continuing operations
12,176
9,888
Income loss from discontinued operations, net of tax
(12)
(19)
Net income
$
12,164
$
9,869
Basic net income per share:
Income from continuing operations
$
0.21
$
0.17
Loss from discontinued operations, net of tax
—
—
Net income per share
$
0.21
$
0.17
Basic weighted average shares outstanding
58,702
57,636
Diluted net income per share:
Income from continuing operations
$
0.20
$
0.17
Loss from discontinued operations, net of tax
—
—
Net income per share
$
0.20
$
0.17
Diluted weighted average shares outstanding
59,179
58,461

CONDENSED CONSOLIDATED STATEMENTS OF ~~SHAREHOLDERS’~~SHAREHOLDERS’ EQUITY (Unaudited)

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

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

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

Table of Contents

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.~~oil, natural gas and natural gas liquids ("NGLs") properties. As operator, the Company has production operations and conducts exploration ~~and development~~ activities in Gabon ~~West Africa.~~and Canada and hold interests in two production sharing contracts ("PSCs") in Egypt. The Company ~~also~~ has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, VAALCO has discontinued operations associated with activities in Angola, West ~~Africa.~~Africa and Yemen.

The Company’s consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited, VAALCO Energy, Inc. (UK Branch) ~~and~~, VAALCO Energy (USA), Inc, VAALCO Energy (International), LLC, VAALCO Energy (Holdings), LLC, TransGlobe Energy Corporation, TG Energy UK Ltd, TransGlobe Petroleum International Inc., TG Holdings Yemen Inc., TransGlobe West Bakr Inc., TransGlobe West Gharib Inc., TG Energy Marketing Inc., and TG NW Gharib Inc., TG S Ghazalat 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~~10-K for the year ended December 31, ~~2021,~~ 2022, which includes a summary of the significant accounting policies.

~~With respect~~

On October 5, 2022, the Organization of the Petroleum Exporting Countries, Russia and other allied producing countries (collectively, "OPEC+") announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022 through December 2023. On April 3, 2023, OPEC+ reaffirmed this reduction and announced additional voluntary reductions totaling 1.2 MMBbls through December 2023 by various members in addition to the ~~novel strain~~500 MBbls per day voluntary reduction already announced by Russia in February 2023. Included in the 1.2 MMBbls per day reduction was a voluntary reduction by the Gabonese government of ~~coronavirus (“COVID-19”),~~ d~~uring 2021, and continuing in 2022, crude~~8 MBbls per day. The Company has not received any mandate to reduce its current oil ~~prices have experienced significant improvement and oil demand has stabilized over multiple quarters removing much~~production from the Etame Marin block as a result of the uncertainty and instability in the industry. COVID-19 related travel restrictions have gradually eased as governments and people continue to have increasing access to vaccines that help reduce the spread of COVID-19. Further there are indicators of improving economic activity to pre-COVID-19 levels while managing the risk of a resurgence.OPEC+ initiatives.

In July 2021, OPEC+ agreed to increase production beginning in August 2021 and to gradually phase out prior production cuts by September 2022. The decision to continue to increase production was reaffirmed by an OPEC+ meeting held on March 31, 2022. For the ~~three months ended March 31, 2022, the average brent crude oil price was over $100 per barrel.~~

The average ~~brent~~Brent crude oil price for the three months ended March 31, ~~2021,~~ 2023 was $81 per barrel. The average Brent Crude oil price for the three months ended March 31, 2022, June 30, ~~2021,~~ 2022, September 30, ~~2021~~ 2022 and December 31, ~~2021~~ 2022 was ~~$61~~$100 per barrel, ~~$69~~$113 per barrel, ~~$73~~$100 per barrel and ~~$79~~$88 per barrel, respectively.

During the year ended December 31, 2022 and continuing into 2023, the Company noticed that the lead times associated with obtaining materials to support its operations and drilling activities have lengthened and, in some cases, prices for fuel and materials have increased. Management believes the ongoing war between Russia and Ukraine and the slowdown of the economy in China and their related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy. In addition, increased inflation and higher interest rates are impacting the global supply chain market.

While the current ~~community~~commodity price environment is still favorable and the Company has not experienced material disruptions to its operations as a result of ~~COVID-19 any new outbreak~~COVID-19 or ~~emergence~~as result of ~~a new variant.~~ other forces, including the Russia/Ukraine conflict or slowdown in the Chinese economy affecting the global market or further deteriorations of the global supply chain market may have a material adverse impact on financial results and business operations of the Company, including the timing and ability of the Company to complete future drilling campaigns and other efforts required to advance the development of its crude oil, ~~and~~ natural gas and NGLs properties.

Table of Contents

Principles of consolidation – The accompanying unaudited condensed consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation.

Use of estimates – The preparation of the Financial Statements in conformity with ~~generally accepted accounting principles in the United States (“U.S.”) (“GAAP”)~~GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.

Estimates of crude oil, natural gas and NGLs reserves used to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. Due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information becomes available.

Cash and cash equivalents – Cash and cash equivalents ~~includes~~include deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. From time to time, cash balances may exceed the insured amounts, however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks.

Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts in restricted cash at March 31, ~~2022~~ 2023 and ~~2021~~2022 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”), representing bank guarantees for customs clearance in ~~Gabon and funds paid in advance to a counterparty related to the Company’s derivative transactions (see~~ ~~Note 8~~ ~~for further discussion).~~Gabon. Long-term amounts at March 31, ~~2022~~ 2023 and ~~2021~~2022 include a charter payment escrow for the FPSO offshore Gabon as discussed in Note 10 and amounts set aside for the future abandonment of the Etame Marin block. The Company invests restricted and excess cash in readily redeemable money market funds. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows.

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

The Company conducts regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on the unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments. See Note 10 for further discussion.

On February 28,2019, the Gabonese branch of the international commercial bank holding the abandonment funds in a U.S. dollar ("USD") denominated account advised the Company that the bank regulator required transfer of the funds to the Bank Of Central African States (BEAC) which is the Central Bank ~~(“Central Bank”) for African~~of the Economic and Monetary Community ~~(“CEMAC”),~~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 PSC”)~~PSC provides these payments must be denominated in ~~U.S. dollars~~USD and the CEMAC regulations provide for ~~the~~ establishment of a ~~U.S. dollar~~USD account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests ~~until February 2021.~~since they were working on an abandonment fund common policy for the oil and gas Industry as well as the mining industry. As a result, the Company was not able to make the annual abandonment funding ~~payments in~~ payment for the years 2019 ~~2020 or 2021~~ through 2022 totaling ~~$4.3~~$5.8 million, net to VAALCO based on the 2018 abandonment study. In February of 2021, the Bank of Central African State (“BEAC”) authorized the Company to apply for a U.S. dollar denominated escrow account for the abandonment fund at Citibank Gabon (“Citibank”). WorkingOn January 12, 2023, after continued discussions with ~~Citibank, on March 12, 2021 the Company filed the application to open the account~~various BEAC and ~~is currently awaiting the approval of the account from the Central Bank. Accordingly,~~government officials, the Company was ~~not able~~allowed to ~~make our~~re-establish a USD denominated account and made whole for the original USD amount of $37.3 million that was in the account prior to conversion to a local currency account in 2019.

In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $15.6 million in ~~2021. In December 2021, as part of the new FX regulations issued by BEAC, BEAC allowed for the opening of U.S. dollars escrow accounts for the abandonment funds at BEAC.~~ March 2023.

The Company is ~~currently~~ working with ~~the extractive industry~~Directorate of Hydrocarbons in Gabon on establishing a payment schedule to formulate the agreements, which are expected to be finalized in 2022, that regulate these accounts. Accordingly, pursuant to Amendment No. 5 of the Etame PSC that required these funds to be in U.S. dollars, once the account for the U.S. dollars abandonment fund is open at BEAC we will resume ~~our~~ funding of the abandonment fund in compliance with the Etame PSC.

Table of Contents

Accounts with joint venture owners, net – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and production expenditures made by the Company as an operator.

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

Accounts Receivable, net– 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 theCompany’s trade accounts receivable results from sales of crude oil, natural gas, and ~~a corresponding income charge for bad debts, which appears in the “Bad debt expense and other” line item of the condensed consolidated statements of operations.~~

~~As of March 31, 2022, the outstanding VAT receivable balance, excluding the~~ NGLs. For credit losses associated with accounts with trade receivables, seeallowance for bad debt, was approximately $15.8 million ($10.2 million, net to VAALCO). As of March 31, 2022, the exchange rate was XAF 590.1 = $1.00. As of December 31, 2021, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $14.5 million ($9.6 million, net to VAALCO). As of December 31, 2021, the exchange rate was XAF 578.2 = $1.00. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other, net” line item of the condensed consolidated statements of operations.credit losses below.

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

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

Other receivables, net– Under the terms of the Etame PSC, the Company can be required to contribute to meeting domestic market needs of the Republic of Gabon by delivering to it, or another entity designated by the Republic of Gabon, an amount of crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In 2021, the Company was notified by the Republic of Gabon to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. The Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered. Since the ~~crude-oil~~crude oil produced by the Company was not compatible with the ~~crude-oil~~crude oil requirements of the refinery, the Company entered into 2two contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that ~~was more~~produced the compatible tooil the refinery needs and another contract with the refinery itself to deliver the crude ~~oil to.~~oil. Under the contract with ~~another producer,~~ the ~~producer~~provider of the crude oil, the third-party provider is entitled to a selling price consistent with the price the Company receives under the terms of the Etame ~~PSC.~~PSC for the delivery of the crude oil to the refinery. As a result of these contracts and timing differences between when the oil is procured and when it is delivered to and paid for by the refinery, included in the Company’s March 31, ~~2022~~ 2023 condensed consolidated balance sheet ~~is other~~are current receivables in the "other, net" line item of approximately ~~$11.6~~$16.8 million for amounts due to the Company from the refinery ~~and~~for 228 MBbls delivered to the refinery, a ~~$11.6~~$17.9 million current liability included in ~~accrued liabilities~~the "Account payable" line item for amounts due to the oil ~~supplier.~~supplier for 195 MBbls of purchased crude oil from the supplier in the second half of 2022 and a $2.5 million current liability included in the "Accrued liabilities and other" line item for amounts due to the oil supplier for 32.5 MBbls of crude oil purchased in March 2023.

~~Prepayments~~

On January 19, 2022, TransGlobe’s West Gharib, West Bakr and ~~Other~~North West Gharib (collectively the "Eastern Desert") concessions were merged into the Merged Concession Agreement with the Egyptian General Petroleum Corporation ("EGPC"). The Merged Concession includes improved cost recovery and production sharing terms scaled to oil prices with a new 15-year development term and a 5-year extension option. Upon execution of the Merged Concession, there was an effective date adjustment owed to the Company for the difference between historic and Merged Concession Agreement commercial terms applied against Eastern Desert production from the Merged Concession Effective Date, February 1, 2020. The cumulative amount of the effective date adjustment was estimated at $67.5 million and was recorded as part of the TransGlobe Arrangement. During the fourth quarter of 2022, the Company received $17.2 million of the receivable. At March 31, 2023, the remaining $50.3 million was recorded on the condensed consolidated balance sheet in current receivables in the "Other, net" line item. The Company continues to work with the marketing and scheduling department of EGPC, as well as the Ministry, to crystallize cargoes against the back dated receivable.

For credit losses associated with other receivables, seeallowance for credit losses below.

Value added tax and other receivables, net – ~~Included~~The Company incurs receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”). For the allowance associated with VAT, see allowance for credit losses and other below. Since VAT is assessed under a foreign taxing authority, the allowance falls outside of the scope of the credit loss standard.

As of March 31, 2023, the outstanding VAT receivable balance, excluding the allowance, was approximately $22.9 million ($14.9 million, net to VAALCO). As of March 31, 2023, the exchange rate was XAF 602.976 = $1.00. As of December 31, 2022, the outstanding VAT receivable balance, excluding the allowance, was approximately $21.8 million ($13.9 million, net to VAALCO). As of December 31, 2022, the exchange rate was XAF 612.6 = $1.00. The receivable amount, net of allowances, is reported as a non-current asset in ~~“Prepayments~~the “Value added tax and ~~other”~~other receivables” line item in the unaudited 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 expense, net” line item of the condensed consolidated statements of operations and comprehensive income.

Allowance for credit losses and other – On January 1, 2023, the Company adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”). ASU 2016-13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates.

Table of Contents

The Company estimates the current expected credit losses based primarily using an either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance ~~sheet~~ or when the Company has determined that the balance will not be collected.

The Company has identified the following types of financial assets that are within the scope of ASU 2016-13:

•	Accounts receivable with joint venture owners;
•	Trade accounts receivables;
•	Other receivables

As a result of adopting ASU 2016-13 on January 1, 2023, the Company recognized a $3.1 million provision ($18.2 million other receivable balance excluding the provision) for current expected credit losses on its other receivables related to amounts owed to the Company from the refinery in Gabon through a cumulative effect adjustment offset to retained earnings. During the three months ended March 31, 2023, the Company recorded an additional provision of $0.4 million for the oil delivered to the refinery during the quarter.

Also on January 1, 2023, the Company transferred its $0.3 million provision related toaccounts with joint venture owners from an allowance for bad debt account to an expected credit loss account. As of March 31, 2023, the Company has established a credit loss allowance for the full $0.3 million receivable from one of the non-operating partners in Block P offshore Equatorial Guinea. The Company is working with its partner on collecting payment.

During the three months ended March, 31, ~~2022 are $3.9~~2023, the Company recognized an additional $0.6 million ~~of prepayments~~provision related to ~~fixed assets~~its Value added tax with Gabon.

With respect to the Company’s receivable from the refinery and ~~$2.1 million~~TVA receivable balances, collection efforts, including remedies provided for in the contracts, are being pursued to collect overdue amounts owed to the Company. The Company is in ongoing discussions with the Ministry of ~~prepayments related~~the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to ~~royalty expenses.~~the realization of the past due balances.

The following table provides an analysis of the change of the aggregate credit loss allowance and other allowances.

	*Three Months Ended March 31,*
	*2023*			*2022*
	*(in thousands)*
Allowance for credit losses and other
Balance at beginning of period	$	(8,704	)	$	(5,741	)
Credit loss charges and other, net of receipts		(935	)		(492	)
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023		(3,120	)		—
Foreign currency gain (loss)		(73	)		98
Balance at end of period	$	(12,832	)	$	(6,135	)

Table of Contents

Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable ~~value and~~value. In Gabon, inventories represent the Company's share of crude oil produced and stored on the FSO at March 31, 2023 or the FPSO at March 31, 2022, but unsold at the end of the period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. The Company has made the decision to keep an inventory of crude in Egypt rather than perform direct sales in order to push for an export cargo during the second quarter of 2023. At March 31, 2023, the Company is in an underlift situation in Egypt.

Prepayments and Other – Included in “Prepayments and other” line item of the Company’s March 31, 2023 condensed consolidated balance sheet are $2.5 million of prepayments related to fixed assets, $1.6 million of prepayments related to royalties in Gabon, $1.9 million in prepaid insurance and other, $3.9 million related to prepaid fuel in Egypt, $2.2 million in advances to contractors, and $5.3 million in other prepaid items.

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

Crude Oil and natural gas properties, equipment and other – The Company uses the successful efforts method of accounting for crude oil, ~~and~~ natural gas and NGLs 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.

Capitalized Equipment Inventory – Capitalized equipment inventory represents the costs incurred in bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Capitalized equipment inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle.

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

Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a block basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a block basis under the unit-of-production method based upon estimates of proved reserves. Support equipment (other than equipment inventory) and leasehold improvements related to crude oil, ~~and~~ natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, ~~and~~ natural gas and NGLs 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.

Table of Contents

Impairment– The Company reviews the crude oil, ~~and~~ natural gas and NGLs producing properties for impairment on a block basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or if commodity prices fall below a level that significantly ~~effects~~affects anticipated future cash flows. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 (as defined in the policy "Fair value" below) inputs that are based upon estimates the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, ~~and~~ natural gas and NGLs 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 and NGLs 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 and NGLs 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, Canada, Egypt and in Block P in Equatorial Guinea. See Note 7 for further discussion.

Purchase Accounting – On ~~February 25, 2021, VAALCO Gabon S.A., a wholly owned~~October 13, 2022, the Company and AcquireCo, an indirect wholly-owned subsidiary of the Company, completed the business acquisition of ~~Sasol Gabon S.A.’s (“Sasol’s”) 27.8% working interest in the Etame Marin block offshore Gabon~~TransGlobe and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the ~~sale and purchase agreement (“SPA”) dated November 17, 2020 (the “Sasol Acquisition”).~~ Arrangement Agreement on July 13, 2022. The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. In order to allocate the purchase price, the Company developed fair value models with the assistance of outside consultants. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 3 for further discussion.

Lease commitments – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, ~~Leases~~. Leases. Further, if a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and a lease liability at the present value of the future lease payments. ROU assets for operating leases are recorded under “Right of use operating lease assets” and the current portion and long-term portion of the lease liabilities for operating leases are reflected in “Operating lease liabilities – current portion” and “Operating lease liabilities – net of current portion” within the condensed consolidated balance sheets. ROU assets for financing leases are recorded within “Right of use ~~financing~~finance lease assets” and the current portion and long-term portion of the lease liabilities for financing leases are reflected in ~~“Financing~~“Finance lease liabilities – current portion” and ~~“Financing~~“Finance lease liabilities – net of current portion” within the condensed consolidated balance sheets.

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

A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with crude oil, ~~and~~ natural gas and NGLs properties. The Company uses current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil, ~~and~~ natural gas and NGLs properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised, and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for crude oil, ~~and~~ natural gas and NGLs production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. See Note 1213 for further discussion.

Table of Contents

Revenue recognition– The Company's revenues are derived primarily from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers.

Revenues from contracts with customers are ~~generated from sales in Gabon pursuant to crude oil sales and purchase agreements.~~ ~~There is~~recognized when the Company satisfies a ~~single~~ performance obligation ~~(delivering crude~~by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the ~~delivery point, i.e.~~customer and the ~~connection to the customer’s crude oil tanker) that gives rise to revenue recognition~~customer taking physical possession. VAALCO mainly satisfies its performance obligations at ~~the~~a point in time ~~when~~and the amounts of revenues recognized relating to performance ~~obligation event takes place.~~ obligations satisfied over time are not significant. See Note 6 for further discussion.

In ~~addition to revenues from customer contracts,~~ connection with the acquisition of TransGlobe on October 13, 2022, the Company has ~~other revenues related~~elected to ~~contractual provisions under~~continue its policy regarding shipping and handling costs and are presenting these costs net within revenue in the ~~Etame PSC. The Etame PSC is not a customer contract. The terms~~consolidated statements of operations and comprehensive income. In addition, the Company has elected to recognize revenue from oil, natural gas and NGL’s on the basis of the ~~Etame PSC includes provisions for payments to~~Company’s net working interest, less royalties on the ~~government~~consolidated statements of ~~Gabon for: royalties~~operations and comprehensive income. Any imbalances from an underlift or overlift position are valued based on ~~13% of production at~~ the ~~published price and a shared portion of “Profit Oil” determined based on daily~~

production rates, as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments. See Note 6 for further discussion.actual sales proceeds received.

Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs.

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

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

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

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

Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 1415 for further discussion.

Foreign currency transactions – The U.S. dollar is the functional currency of most of the Company’s foreign operating subsidiaries. However, in connection with the Company’s acquisition of TransGlobe, the Company acquired TransGlobe’s Canadian operations whose functional currency is the Canadian dollar. When the Company’s subsidiaries' functional currency is the US dollar, gains and losses on foreign currency transactions are included in income. When the Company’s subsidiaries' functional currency is the local currency, not the US dollar, the cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income. Both realized and unrealized foreign exchange gain and losses are recorded within the condensed consolidated statements of operations and comprehensive income line item “Other (expense) income, net”.

Table of Contents

Income taxes – The annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or the level of operations or profitability in each jurisdiction would impact the tax liability in any given year. The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil, ~~and~~ natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined. WeThe Company also record as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil which results due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted.

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

In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, the Company has not recognized deferred tax assets. Should the expectations change regarding the expected future tax consequences, the Company may be required to record additional deferred taxes that could have a material effect on the condensed consolidated financial position and results of operations. See Note 1516 for further discussion.

Derivative instruments and hedging activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of ~~our~~the Company's 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. The Company has elected not to offset fair value amounts of qualifying derivatives under a master netting arrangement and associated fair value amounts for cash collateral receivables and payables. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments loss, net” line item located within the “Other income (expense)” section of the condensed consolidated statements of ~~operations.~~operations and comprehensive income. See Note 8 for further discussion.

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

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

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

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

Nonrecurring Fair Value Measurements – The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil, ~~and~~ natural gas and NGLs properties, asset retirement assets and liabilities and other long-lived assets and assets acquired and liabilities assumed in a business combination. Generally, a cash flow model is used in combination with inflation rates and credit-adjusted, risk-free discount rates or industry rates to determine the fair value of the assets and liabilities. Based upon ~~our~~the Company's review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.

Table of Contents

Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, accrued liabilities, liabilities for SARs and guarantees. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using ~~level~~ Level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance ~~sheet.~~sheet while the long-term portion is reported in “Other long-term liabilities”. With respect to ~~the other financial instruments included in current assets~~cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these ~~instruments.~~

As of March 31, 2022
Balance Sheet Line
Level 1
Level 2
Level 3
Total
(in thousands)
Liabilities
SARs liability
Accrued liabilities and other
$
—
$
1,422
$
—
$
1,422
Derivative liability - crude oil swaps
Accrued liabilities and other
—
24,064
—
24,064
$
—
$
25,486
$
—
$
25,486
As of December 31, 2021
Balance Sheet Line
Level 1
Level 2
Level 3
Total
(in thousands)
Liabilities
SARs liability
Accrued liabilities and other
$
—
$
609
$
—
$
609
Derivative liability - crude oil swaps
Accrued liabilities and other
—
4,806
—
4,806
$
—
$
5,415
$
—
$
5,415

instruments and are considered Level 1 inputs. The Company generally extends unsecured credit to these clients; therefore, collection of receivables may be affected by the economy surrounding the oil and natural gas industry or other economic conditions. The Company closely monitors extensions of credit and may negotiate payment terms that mitigate risk.

		*As of March 31, 2023*
	*Balance Sheet Line*	*Level 1*		*Level 2*		*Level 3*		*Total*
		*(in thousands)*
Assets
Derivative asset	Prepayments and other	$	—	$	124	$	—	$	124
		$	—	$	124	$	—	$	124
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	297	$	—	$	297
		$	—	$	297	$	—	$	297

`		As of December 31, 2022
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		*(in thousands)*
Assets
Derivative asset	Prepayments and other	$	—	$	102	$	—	$	102
		$	—	$	102	$	—	$	102
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	556	$	—	$	556
		$	—	$	556	$	—	$	556

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.

Other, net – “Other, net” in non-operating income and expenses includes gains and losses from foreign currency transactions as discussed above, as well as taxes other than income taxes.

Other comprehensive income – All of the Company’s other comprehensive income arises from TransGlobe's Canadian operations whose functional currency is the Canadian dollar. Translation gains and losses occur when translating the financial statements of non-U.S. functional currency operations to the USD. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the consolidated statements of operations and comprehensive income. Translations occur as follows:

	•	Income and expenses are translated at the date of the transaction.
	•	Assets and liabilities are translated at the prevailing rate on the balance sheet date. The exchange rate to convert Canadian dollars (“CAD") to US dollars (“USD”) at December 31, 2022 and at March 31, 2023 was 0.738 USD and 0.739, respectively.

Table of Contents

2.NEW ACCOUNTING STANDARDS

~~Not Yet Adopted~~

Adopted

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. ~~2016-13,~~ 2016-13,Financial Instruments – Credit Losses (Topic ~~326)~~326): Measurement of Credit Losses on Financial Instruments (“(“ASU ~~2016-13”~~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. Thisis significantly different from the current model that increases the allowance when losses are probable. ~~Initially,~~ ASU ~~2016-13 was~~2016-13 is effective for ~~all public~~Securities and Exchange Commission filers, excluding smaller reporting companies, for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. As a smaller reporting company, through December 31, 2022, the Company was required to adopt the new standard for the fiscal years ~~and will be applied with~~beginning after December 15, 2022, including interim periods within those fiscal years.

The Company adopted ASU 2016-13 ("ASC 326") on January 1, 2023 using the modified-retrospective approach. The modified-retrospective approach consists of applying the amendments in ASU 2016-03 through a cumulative-effect adjustment, if required, 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”~~Company’s current method and timing of recognizing credit losses is in accordance with ASC 326 and is consistent with the previous method of recognizing credit losses, except for one receivable, which now utilizes the Discounted Cash Flow method for computing its Expected Credit Loss ("ECL"): ~~Codification Improvements~~. The Company recorded an ECL allowance of $3.1 million as an opening balance adjustment 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~~ retained earnings at January 1, ~~2020 to January~~ 2023. See Note 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.~~further details.

3. ACQUISITIONS AND DISPOSITIONS

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

TransGlobe Merger

On ~~February 25, 2021, VAALCO Gabon S.A.~~October 13, 2022, the Company and AcquireCo completed the ~~acquisition~~previously announced business combination with TransGlobe whereby AcquireCo acquired all of ~~Sasol’s 27.8% working interest in~~ the ~~Etame Marin block offshore Gabon~~issued and outstanding common shares of TransGlobe and TransGlobe became a direct wholly owned subsidiary of AcquireCo and an indirect wholly owned subsidiary of the Company pursuant to an arrangement agreement entered into by the Company, AcquireCo and TransGlobe on July 13, 2022 (the “Arrangement Agreement”).

At the effective time of the Arrangement and pursuant to the ~~SPA.~~Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement (the “TransGlobe common shares”) was converted into the right to receive 0.6727 (the “exchange ratio”) of a share of common stock, par value $0.10 per share, of the Company (“VAALCO common stock,” and each share of VAALCO common stock, a “VAALCO share”). The ~~effective~~total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million. The Arrangement resulted in VAALCO stockholders owning approximately 54.5%, and TransGlobe shareholders owning approximately 45.5% of the combined company (the “Combined Company”), calculated based on vested outstanding shares of each company as of the date of the ~~transaction was July 1, 2020.~~ Arrangement Agreement.

Prior to the ~~Sasol Acquisition,~~Arrangement, TransGlobe was a cash flow-focused oil and gas exploration and development company whose activities were concentrated in the Arab Republic of Egypt and Canada. The Combined Company is a leading African-focused operator with a strong production and reserve base and a diverse portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada. The transaction qualifies as a business combination under ASC 805, Business Combinations and the Company ~~owned and operated a 31.1% working interest~~is the accounting acquiror. The purchase accounting for the business combination has not been completed.

During the three months ended March 31, 2023, the deferred tax liability in ~~Etame. The Sasol Acquisition~~Egypt was increased ~~the Company’s working interest to 58.8%. As a result~~by $1.4 million as of the ~~Sasol Acquisition,~~date of the ~~net portion of production and costs relating~~Arrangement. This resulted in a decrease to the ~~Company’s Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results~~bargain purchase gain of a corresponding $1.4 million for the ~~interests acquired~~three months ended March 31, 2023 and is reflected in our condensed consolidated statements of operations in the ~~Sasol Acquisition have been included in VAALCO’s results for periods after February 25, 2021.~~line, "Other expense, net".

Table of Contents

The ~~following amounts represent the allocation~~actual impact of the ~~purchase price~~Arrangement was an increase to ~~the assets acquired~~“Crude oil, natural gas and ~~liabilities~~ ~~assumed~~NGLs sales” of $43.7 million and $9.7 million of “Net income” in the ~~Sasol Acquisition.~~condensed consolidated statements of operations and comprehensive income for the three months ended March 31, 2023.

	*October 13, 2022*		*Measurement Period Adjustment*		*October 13, 2022 (As Adjusted)*
	*(in thousands)*		*(in thousands)*		*(in thousands)*
Purchase Consideration
Common stock issued to TransGlobe shareholders	$	274,145	$	—	$	274,145

	*October 13, 2022*			*October 13, 2022*			*October 13, 2022*
	*(in thousands)*			*(in thousands)*			*(in thousands)*
Assets acquired:
Cash	$	36,686		$	—		$	36,686
Wells, platforms and other production facilities		243,669			—			243,669
Equipment and other		2,099			—			2,099
Undeveloped acreage		30,216			—			30,216
Accounts receivable - trade		48,068			—			48,068
Accounts receivable - other		50,275			—			50,275
Accounts with joint venture owners		68			—			68
Right of use operating leases		1,609			—			1,609
Right of use financing leases		204			—			204
Prepayment and other		7,627			—			7,627
Liabilities assumed:								-
Asset retirement obligations		(6,134	)		—			(6,134	)
Accounts payable		(10,223	)		—			(10,223	)
Accrued liabilities and other		(50,128	)		—			(50,128	)
Operating lease liabilities - current portion		(961	)		—			(961	)
Financing lease liabilities - current portion		(125	)		—			(125	)
Operating lease liabilities - net of current portion		(688	)		—			(688	)
Financing lease liabilities - net of current portion		(21	)		—			(21	)
Deferred tax liabilities		(40,964	)		(1,412	)		(42,376	)
Other long-term liabilities		(26,313	)		—			(26,313	)
Bargain purchase gain		(10,819	)		1,412			(9,407	)
Total purchase price	$	274,145		$	—		$	274,145

17 Table of Contents
		~~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,~~TransGlobe, including crude oil, ~~and~~ natural gas and NGLs 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,~~October 13, 2022, 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~~a 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 specific risk ~~adjusted~~adjustment factors based on reserve category discount rates. Other significant estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The ~~Company had one year from the date of closing to record~~ purchase price ~~adjustments as a result~~allocation is preliminary pending final determination of ~~changes in such estimates.~~the fair values of certain assets and liabilities, primarily the accounts receivable, asset retirement obligations, accounts payable and any contingencies, and any related tax impacts. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, ~~a $7.7~~an initial $10.8 million bargain purchase gain was recognized. AAs a result of the transition period adjustment, the initial bargain purchase gain ~~of $5.5 million is included in “Other, net” under “Other income (expense)” in the 2021 condensed consolidated statements of operations. An income tax benefit of $2.2 million, related~~has been reduced to ~~the bargain purchase gain, is also included in the 2021 condensed consolidated statements of operations.~~$9.4 million. The bargain purchase gain ~~is primarily attributable~~was due to the ~~increase~~decrease in ~~crude oil~~the share price ~~forecasts~~of VAALCO stock from the ~~date~~time period when the ~~SPA~~arrangement agreement was signed, ~~November 17, 2020,~~July 13, 2022 and the share price at closing, October 13, 2022 while the exchange ratio, of TransGlobe shares converted to VAALCO shares, remained the ~~closing date, February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.~~same.

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

The unaudited pro forma results presented below have been prepared to give the effect toof the ~~Sasol Acquisition~~TransGlobe Arrangement discussed above on the Company’s results ~~of operations~~ for the three months ended March 31, 2022, ~~and March 31, 2021, respectively,~~ as if the ~~Sasol Acquisition~~Arrangement had been consummated on January 1, ~~2020.~~ 2021. The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the ~~Sasol Acquisition~~TransGlobe Arrangement had been completed on such date or to project the Company’s results of operations for any future date or period.

Three Months Ended March 31,
2021
(in thousands)
Pro forma (unaudited)
Crude oil and natural gas sales
$
57,547
Operating income
25,025
Net income
11,736
(a)
Basic net income loss per share:
Income from continuing operations
$
0.20
Net income per share
$
0.20
Basic weighted average shares outstanding
57,636
Diluted net income per share:
Income from continuing operations
$
0.20
Net income per share
$
0.20
Diluted weighted average shares outstanding
58,461

	*Three Months Ended March 31,*
	*2022*
	*(in thousands)*
Pro forma (unaudited):
Crude oil, natural gas and natural gas liquids sales	$	121,127	*(a)*
Operating income	$	61,427	*(b)*
Net income	$	31,039	*(c)*


Basic net income per share:	$	0.29
Basic weighted average shares outstanding		108,009

Diluted net income per share:	$	0.29
Diluted weighted average shares outstanding		108,486

~~________________~~

(a)	The unaudited pro forma net revenues associated with Crude oil, natural gas and natural gas liquids sales have been adjusted for shipping and handling costs based on the Company’s historical policy and revenue recognition is based on the Company’s working interest, less royalties, the entitlement method.
(b)	The unaudited pro forma operating income for the three months ended March 31, 2022 removes the $26.0 million impairment reversal recorded by TransGlobe in 2022, and reclassifies depreciation for certain leases identified as operating leases, to production expense and adjusts depreciation, depletion and amortization expense related to the depletable assets and asset retirement obligations acquired in the Arrangement based on the purchase price allocation.
(c)	The unaudited pro forma net income for the year ended March 31, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense.

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

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

Discontinued Operations - Angola and Yemen

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.~~operations and comprehensive income. 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 the three months ended March 31, ~~2022~~ 2023 and ~~2021~~,2022, the Angola segment did not have a material impact on the Company’sfinancial position, results of operations, cash flows and related ~~disclosures~~.disclosures.

As part of the Arrangement with TransGlobe, the Company acquired TG Holdings Yemen Inc. who previously owned TransGlobe's interests in four PSAs in Yemen: Block 32, Block 72, Block 75 and Block S-1. In January 2015, TransGlobe relinquished its interests in Block 32 and Block 72 in Yemen (effective dates of March 31, 2015 and February 28, 2015, respectively), and in October 2015 TransGlobe sold its subsidiary that held interests in Block 75 and Block S-1. The operating results of the Yemen segment have been classified as discontinued operations for all periods presented in the Company’s consolidated statements of operations and comprehensive income. The Company segregated the cash flows attributable to the Yemen segment from the cash flows from continuing operations for all periods presented in the Company’s consolidated statements of cash flows. During the three months ended March 31,2023, the Yemen segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

The Company’s operations are based in Gabon and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s 2two reportable operating segments is organized and managed based upon geographic location. The Company’s Chief Executive Officer, who is the chief operating decision maker, and management review and evaluate the operation of each geographic segment separately, primarily based on operating income (loss). The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the location of hydrocarbon production. Corporate and other is primarily corporate and operations support costs that are not allocated to the reportable operating segments.

Segment activity of continuing operations for the three months ended March 31, ~~2022~~ 2023 and ~~2021~~2022 as well as long-lived assets and segment assets at March 31, ~~2022~~2023 and December 31, ~~2021~~2022 are as follows:

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

~~(1)Excludes~~(1) - Includes assets acquired in the ~~Sasol~~TransGlobe acquisition.

Information about the Company’s most significant customers

The Company currently sells crude oil production from Gabon under term crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs") with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The Company ~~signed~~was previously party to a COSPA with ExxonMobil Sales and Supply LLC (“Exxon”) that covered sales from February 2020 through ~~January~~July 2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. ~~The~~This COSPA ~~with Exxon~~ has been ~~amended~~terminated.

Table of Contents

As discussed further in Note 11, on May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”) entered into a facility agreement (the “Facility Agreement”) by and ~~extended several times, most recently~~among the Company, VAALCO Gabon, SA (“VAALCO Gabon”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in ~~January 2022,~~an initial aggregate maximum principal amount available of up to ~~extend~~$50.0 million. In connection with the ~~date~~entry into the Facility Agreement, the Company entered into a COSMA with Glencore pursuant to which the Company agreed to make Glencore the exclusive offtaker and marketer of all of the ~~COSPA through~~crude oil produced from the ~~end~~Etame G4-160 Block, offshore Gabon during the period from August 1, 2022 until the Final Maturity Date of ~~July 2022.~~the Facility (as defined in the Facility Agreement). Pursuant to the COSMA, Glencore agreed to buy and market the Company’s crude oil with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

~~During~~

For the three months ended March 31, ~~2022 and 2021 revenues from~~ 2023 sales of crude oil to ~~Exxon were~~Glencore made up 100% of Etame revenues. For the three months ended March 31, 2022 sales of crude oil to ExxonMobil Sales and Supply LLC made up 100% of Etame revenues. For the three months ended March 31, 2023, Mercuria covered 100% of the Company’s ~~total~~ crude oil sales in Egypt. For the three months ended March 31, 2023, revenues ~~from customers.~~in Canada were concentrated in two separate customers that constituted approximately 59% and 21% of revenues. Concentrations of accounts receivable are similar to the revenue percentages.

5.EARNINGS PER SHARE

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

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

	*Three Months Ended March 31,*
	*2023*			*2022*
	*(in thousands)*
Net income (loss) (numerator):
Income (loss) from continuing operations	$	3,483		$	12,176
Income from continuing operations attributable to unvested shares		18			(140	)
Numerator for basic		3,501			12,036
Loss from continuing operations attributable to unvested shares		(18	)		—
Numerator for dilutive	$	3,483		$	12,036

Loss from discontinued operations, net of tax	$	(13	)	$	(12	)
Loss from discontinued operations attributable to unvested shares		—			—
Numerator for basic		(13	)		(12	)
(Income) loss from discontinued operations attributable to unvested shares		—			—
Numerator for dilutive	$	(13	)	$	(12	)

Net income (loss)	$	3,470		$	12,164
Net income attributable to unvested shares		(29	)		(139	)
Numerator for basic		3,441			12,025
Net (income) loss attributable to unvested shares		(18	)		—
Numerator for dilutive	$	3,423		$	12,025

Weighted average shares (denominator):
Basic weighted average shares outstanding		107,387			58,702
Effect of dilutive securities		1,365			477
Diluted weighted average shares outstanding		108,752			59,179
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		195			139

Table of Contents

6. REVENUE

Gabon

Three Months Ended March 31,
2022
2021
(in thousands)
Net income (numerator):
Income from continuing operations
$
12,176
$
9,888
Income from continuing operations attributable to unvested shares
(140)
(187)
Numerator for basic
12,036
9,701
Income from continuing operations attributable to unvested shares
—
—
Numerator for dilutive
$
12,036
$
9,701
Loss from discontinued operations, net of tax
$
(12)
$
(19)
Income from discontinued operations attributable to unvested shares
—
—
Numerator for basic
(12)
(19)
Income from discontinued operations attributable to unvested shares
—
—
Numerator for dilutive
$
(12)
$
(19)
Net Income
$
12,164
$
9,869
Net income attributable to unvested shares
(139)
(187)
Numerator for basic
12,025
9,682
Net (income) loss attributable to unvested shares
—
—
Numerator for dilutive
$
12,025
$
9,682
Weighted average shares (denominator):
Basic weighted average shares outstanding
58,702
57,636
Effect of dilutive securities
477
825
Diluted weighted average shares outstanding
59,179
58,461
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive
139
298

~~6. REVENUE~~

Revenues from contracts with customers are generated from sales in Gabon pursuant to ~~COSPAs.~~ COSPAs or COSMAs. COSPAs or COSMAs with customers are renegotiated near the end of the contract term and may ~~be entered into with a different customer or the same customer going forward.~~

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

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

Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the ~~FPSO~~FSO 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)~~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~~sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. Historically as ~~a reduction in reserves. The~~operator, 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.~~volumes sold exceeded the Company’s ownership interest. However, under the COSMA, each coventurer is responsible for invoicing Glencore their respective ownership interest in the final volumes.

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

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

In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame PSC. The Etame PSC is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606. The terms of the Etame PSC includes provisions for payments to the government of Gabon for: royalties based on 13% of production at the published price, and a shared portion of “Profit Oil” determined based on daily production rates as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame PSC provides that the government of Gabon may settle these obligations in-kind, i.e., taking crude oil barrels, rather than with cash payments.

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

Table of Contents

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

With respect to the government’sshare of Profit Oil, the Etame PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the consolidated statements of operations and comprehensive income, the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. Prior to February 1,2018, the government did not take any of its share of Profit Oil in-kind. These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract. For the in-kind sales by the government beginning February 1,2018, these sales are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, the amount associated with the Profit Oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported in current income tax expense. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, i.e. the period in which it lifts the crude oil. The Company has a ~~$8.8~~$4.5 million foreign income tax payable as of March 31, ~~2022.~~2023 related to Gabon. As of December 31, ~~2021,~~2022, the Company had a foreign taxes ~~payable attributable to this obligation~~receivable of $2.8 million, as the Gabonese government lifted more oil-in-kind than what was ~~$3.1 million.~~ owed in foreign taxes in December 2022.

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

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

	*Three Months Ended March 31,*
	*2023*			*2022*
Revenues from customer contracts:	*(in thousands)*
Sales under the COSPA or COSMA	$	42,601		$	76,486
Other items reported in revenue not associated with customer contracts:
Carried interest recoupment		—			1,112
Royalties		(5,864	)		(8,942	)
Net revenues	$	36,737		$	68,656

Egypt

Revenues from sales in Egypt are generally made through direct sales to EGPC or through contracts with customers pursuant to crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs"). EGPC and the Company’s subsidiary, TransGlobe Petroleum International (“TPI”), each own a 50% interest, respectively, in the operating company which is a party to the Merged Concession Agreement. EGPC and the Company’s subsidiary, TPI, each also own a 50% interest, respectively, in the operating company that is a party to the South Ghazalat concession agreement. 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.

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

Table of Contents

Customer sales generally occur on a daily basis when sales are directly to EGPC or haphazardly production is sold through a cargo lifting. Direct sales to EGPC are considered complete when oil is delivered to EGPC storage facility. When sales are made through cargo lifting, the performance obligations are normally satisfied either when the oil is delivered to the export facility location or when the oil is delivered to its ultimate destination, as specified in the contract. Regardless of the type of sales, there is a single performance obligation (delivering crude oil to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses.

Revenues associated with the sales of the Company’s crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable. For reporting purposes, the Company records EGPC’s share of production as royalties which are netted against revenue, whether EGPC’s share of production arises from EGPC’s share of profit oil or excess cost oil which is discussed below.

Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company. The PSCs provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSCs, the Company's share of excess ranges between 5% and 15%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically, maximum cost oil ranges from 25% to 40% in Egypt. The balance of the production after maximum cost recovery is shared with the government (profit oil). Depending on the contract, the Egyptian government receives 67% to 84% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Typically, the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less cost oil and may receive more profit-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. EGPC’s share of productionwill increase during times of rising oil prices and decrease in times of declining oil prices. If oil prices are sufficiently low and the Gharib Blend/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSCs and any eligible extension periods.

With respect to Egyptian income taxes, which are the Company’s liability under the terms of the Merged Concession Agreement, these taxes are paid by EGPC on behalf of the Company out of EGPC’s share of production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of the Company are recognized as crude oil revenue and income tax expense for reporting purposes.

EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC cooperation and approval to schedule liftings. Once liftings occur, the Company has a 30-day collection cycle on liftings as a result of direct marketing to international purchasers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. Direct sales to EGPC are normally settled two to four weeks from delivery.

In some instances TPI will borrow or loan production volumes in order to achieve a required amount of crude oil for cargo sales. In these instances, TPI can be in an overlift or underlift position. Regardless of being in an over lift or underlift position, sales are based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds and TPI will record a payable, if in an overlift position, or a receivable, if in an underlift position, based on the fair value of the consideration received or receivable.

The following table presents revenues in Egypt from contracts with customers:

	*Three Months Ended March 31,*
	*2023*
Revenues from customer contracts:	*(in thousands)*
Gross sales	$	54,621
Royalties		(19,340	)
Selling costs		(497	)
Net revenues	$	34,784

Table of Contents

Canada

Revenues from the sale of crude oil, natural gas, condensate and natural gas liquids ("NGLs") in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. 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. Prices are determined by reference to quoted market prices in active markets for crude oil, natural gas, condensate, and NGLs based on product, each adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are measured at the transaction price that the Company expects to be entitled in exchange for transferring promised goods to a customerand is determined based at the fair value of the consideration received. VAALCO pays royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime. For reporting purposes, the Company records revenues net of royalties.

Customer sales generally occur on a daily basis when crude oil, natural gas, condensate or NGL’s are sold, normally via pipeline, to a delivery point. Regardless of the type of sales, there is a single performance obligation (delivering crude oil, natural gas, condensate or NGL’s to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses.

Settlement of accounts receivable in Canada occur on the 25th of the following month after production.

The following table presents revenues in Canada from contracts with customers:

	Three Months Ended March 31,
	2023
Revenues from customer contracts:	*(in thousands)*
Oil revenue	$	6,654
Gas revenue		958
NGL revenue		2,463
Royalties		(1,193	)
Net revenues	$	8,882

7.CRUDE OIL, ~~AND~~ NATURAL GAS and NGLs PROPERTIES AND EQUIPMENT

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

	*As of March 31, 2023*			*As of December 31, 2022*
	*(in thousands)*
Crude oil and natural gas properties and equipment - successful efforts method:
Wells, platforms and other production facilities	$	1,432,823		$	1,406,888
Work-in-progress		—			—
Undeveloped acreage		53,999			56,251
Equipment and other		41,176			38,796
		1,527,998			1,501,935
Accumulated depreciation, depletion, amortization and impairment		(1,028,045	)		(1,006,663	)
Net crude oil and natural gas properties, equipment and other	$	499,953		$	495,272

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

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

~~Extension~~

Table of ~~Term of~~ Contents

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

The PSC Extension ~~extended~~extends the term ~~for each of the 3 exploitation areas in~~to operate until September 17,2028. The PSC Extension also grants the Etame ~~Marin block~~Consortium the right for ~~a period~~two additional extension periods of ~~ten~~five years ~~with effect from September 17, 2018, the effective date of the PSC Extension,~~ ~~with 2five-year~~ ~~options to extend the PSC~~.each.

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

On January 20, 2022, the Company announced a fully executed Merged Concession Agreement with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. In connection with the Merged Concession Agreement, the Company is required to make further annual $10.0 million modernization payments from February 2023 through February 2026. In accordance with the Merged Concession, the Company agreed to substitute the February 2023 payment and issue a $10.0 million credit against receivables owed to it from EGPC.

The Merged Concession Agreement contains minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date").

The Egyptian PSCs provide for the government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, if any, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the government and the contractor as defined in the specific PSCs. Each PSC is treated individually in respect of cost recovery and production sharing purposes. The remaining production sharing oil (total production less cost oil) is shared between the government and the contractor as defined in the specific PSC. The Egyptian PSCs do not contain minimum production or sales requirements, and there are no restrictions with respect to pricing of the contractor's sales volumes. Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale.

The following table summarizes the Company's Egyptian PSC terms for the first tranche(s) of production for each block. The contracts have different terms for production levels above the first tranche, which are unique to each contract. The government's share of production increases and the contractor's share of production decreases as the production volumes go to the next production tranche. The Company is the contractor in all of the Company's PSCs.

With the approval of the plan of development in September, 2022, the Block P production sharing contract provides for a development and production period of 25 years for the area associated with the Venus development, to September, 2047. The Block P acreage is 23,144 hectares, with 8,476 hectares being the area associated with the Venus development. The Royalty of the PSC is 10% for the first10,000 bopd, and 11% for the 10,000 bopd to 25,000 bopd tranche. The State’s share of profit oil is 10% to a cumulative production of 25 million bbl. For recovery of between 25 million bbl to 50 million bbl, the State’s share of profit oil increases to 20%. The Contractor is allowed access to cost oil to pay for development and operating costs, with a cost oil maximum of 70%. The PSC is subject to 25% income tax in Equatorial Guinea, with tangible development costs being straight line depreciated for tax purposes over 120 months.

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

There was no triggering event in the ~~quarter~~three months ended March 31, ~~2022~~ 2023 that would cause the Company to believe the value of crude oil, ~~and~~ natural gas and NGLs producing properties should be impaired. Factors considered included higher forward ~~price curves for the first quarter of~~prices from December 31, 2022 and ~~expected~~ capital expenditures in the period related to ~~the Etame Marin block.~~its reserves in Gabon, Egypt and Canada.

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~~the Company's appointment as the operator ~~for~~of 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 to Compania Nacional de Petroleos de Guinea Ecuatorial, (“GEPetrol”) 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. In April 2021, Crown Energy, who held a 5% working interest elected to default on its obligations of Block P. On April 12, 2021, the ~~majority of~~ non-defaulting parties assigned the defaulting party’s interest to the non-defaulting ~~parties.~~parties as required by the Joint Operating Agreement. As a result, VAALCO’s working interest ~~will increase~~increased to 45.9% ~~once~~when the EG MMH ~~approves a new~~approved the fourth amendment to the production sharing contract. As In February of ~~March 31, 2022,~~2023, the Company ~~had $10.0~~acquired an additional 14.1% participating interest, increasing VAALCO’s participating interest in the Block to 60.0%. This increase of 14.1% participating interest increases the Company's future payment to GEPetrol to $6.8 million ~~recorded for the book value~~at first commercial production of the ~~undeveloped leasehold costs associated with the Block P license.~~ Block.

The Company has completed a feasibility study of ~~a standalone production~~the development ~~opportunity~~concept of the Venus discovery on Block P. ~~VAALCO is now proceeding~~On September 16, 2022, the EG MMH approved the submitted plan of development. Final documents to ~~a field~~affect the plan of development ~~concept~~are subject to EG MMH approval. The 2023 budget for the plan was delivered on October 12, 2022 to the MMH and ~~will work closely~~was approved effective November 16, 2022. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March 2023 with updated participating interest. Execution of the ~~other joint venture owners to complete this over the coming months.~~Venus development plan has been initiated. 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.~~plan for the area associated with the Venus development. As of March 31, 2023, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license.

Gabon

As a result of the PSC ~~Extension~~extension discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $6.7 million of the share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame Marin block PSC. As a result of discovering reserves in connection with drilling the South East Etame 4H development well in March 2020, ~~$2.3~~$2.3 million of costs were transferred to proved leasehold costs leaving a remaining $11.5 million in unproved leasehold costs. In connection with the Sasol Acquisition discussed under Note 3, $2.2 million of reserves were attributed to undeveloped properties. The balance of undeveloped leasehold costs related to the Etame Marin block at March 31, ~~2022~~ 2023 was $13.7 million.

Egypt and Canada

In connection with the TransGlobe acquisition discussed under Note 3, the Company added $13.6 million and $16.7 million of undeveloped leasehold costs for Egypt and Canada, respectively. The undeveloped leasehold costs were associated to the probable category of reserves. At March 31, 2023, the undeveloped leasehold costs for Egypt was $13.6 million and Canada was $16.7 million.

Capitalized Equipment Inventory

Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded in the “Other operating ~~income (expense),~~expense, net” line item of the unaudited condensed consolidated statements of operations and comprehensive income but were not material for the three months ended March 31, ~~2022~~ 2023 and ~~2021.~~2022.

Table of Contents

8. DERIVATIVES AND FAIR VALUE

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

On May 6, 2021, the Company entered into commodity swaps at a Dated Brent weighted average price of $66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August 6, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. On September 24, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels. On January 6, 2022, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $76.53 per barrel for the period from and including July 2022 to September 2022 for a quantity of 375,000 barrels. On February 23, 2022, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $85.01 per barrel for the period from and including April 2022 to June 2022 for a quantity of 234,000 barrels. See the table below for the ~~unexpired barrels~~list of outstanding contracts as of March 31, ~~2022.~~2023:

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

Settlement Period

Type of Contract

Index

Average Monthly Volumes

Weighted Average Put Price

Weighted Average Call Price

(Bbls)

(per Bbl)

April 2023 - June 2023

Collars

Dated Brent

95,500

65.00

100.00

While these ~~commodity swaps~~derivative instruments 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. In connection with the RBL facility entered in May 2022, the Company is required to hedge a portion of its anticipated oil production at the time the Company draws down on the borrowing base.

The ~~crude oil swap contracts~~derivative instruments 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~~derivative instrument 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.

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

The following table sets forth the loss on derivative instruments on the Company’s unaudited condensed consolidated statements of ~~operations:~~operations and comprehensive income:

		*Three Months Ended March 31,*
Derivative Item	*Statements of Operations Line*	*2023*			*2022*
		*(in thousands)*
Commodity derivatives	Cash settlements paid on matured derivative contracts, net	$	(59	)	$	(12,500	)
	Unrealized gain (loss)		80			(19,258	)
	Derivative instruments gain (loss), net	$	21		$	(31,758	)

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

Table of Contents

Subsequent Event

On April 3, 2023, the Company entered into additional derivatives contracts for the first quarter of 2023. The details are in the chart below:

Settlement Period	*Type of Contract*	*Index*	*Average Monthly Volumes*		*Weighted Average Put Price*		*Weighted Average Call Price*
			(Bbls)		(per Bbl)		(per Bbl)
July 2023 - September 2023	Collars	Dated Brent		95,000	$	65.00	$	96.00

9. CURRENT ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:

	*As of March 31, 2023*		*As of December 31, 2022*
	*(in thousands)*
Accrued accounts payable invoices	$	21,185	$	28,360
Gabon DMO, PID and PIH obligations		11,569		10,509
Capital expenditures		27,850		26,618
Stock appreciation rights – current portion		297		570
Accrued wages and other compensation		2,626		8,161
ARO Obligation		260		306
Egypt modernization payments		9,373		9,933
Excess cost oil payable		1,297		—
Other		6,250		6,935
Total accrued liabilities and other	$	80,707	$	91,392

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

10.COMMITMENTS AND CONTINGENCIES

Abandonment funding

Under the terms of the Etame PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028, under the 2018 abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In November 2021, an abandonment study was done and the estimate used for this purpose is approximately $81.3 million ($~~47.9~~47.8 million, net to VAALCO) on an undiscounted basis. The abandonment estimate ~~will be~~was presented to the Gabonese Directorate of Hydrocarbons as required by the Etame PSC. ~~Through~~ At March 31, ~~2022, $36.3~~2023, the balance of the abandonment fund was $10.7 million ($~~21.4~~6.3 million, net to VAALCO)on an undiscounted ~~basis has been funded.~~basis. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.

~~On March 5, 2019,~~

In the first quarter of 2023, the Directorate of Hydrocarbons in ~~accordance with certain foreign currency regulatory requirements, the Gabonese branch of an international commercial bank holding the~~Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funds in a U.S. dollar denominated account transferred the funds to the Central Bank for CEMAC, of which Gabon is one of the six member states. The U.S. dollars were converted to local currency with a credit back to the Gabonese branch~~. During the three months ended March 31, 2022, the Company recorded a $0.4 million foreign currency loss~~funding payment associated with the ~~abandonment funding account. During the three months ended March 31, 2021, the Company recorded a $0.5 million foreign currency loss associated with the abandonment funding account.~~ ~~In December 2021, as part of the new FX regulations issued by BEAC, BEAC allowed for opening of U.S. dollars escrow accounts for the abandonment funds at BEAC.~~FPSO retirement. The Company ~~is currently working with the extractive industry to formulate the agreements which are expected to be finalized~~received payment of $15.6 million in ~~2022, that regulate these accounts. Accordingly, pursuant to Amendment No. 5~~March 2023.

Table of the Etame PSC that required these funds to be in U.S. dollars, once the account for the U.S. dollars abandonment fund is open at BEAC we will resume our funding of the abandonment fund in compliance with the Etame PSC.

Contents

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 2 two one~~one-year~~-year periods beyond September 2020. These elections ~~have been~~were made, and the charter ~~has been~~was 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 On September 9, 2022, the Company ~~believes~~signed an addendum to the ~~need for~~

~~performance under~~FPSO contract which extended the charter guarantee is remote, the Company recorded a liability of $0.1 million as of March 31, 2022 and $0.1 million as of December 31, 2021 representing the guarantee’s estimated fair value. Estimated future minimum obligations as of March 31, 2022 through the enduse of the FPSO ~~charter in September~~through October 4, 2022 ~~are approximately $15.9~~and ratified certain decommissioning and demobilization items associated with exiting the contract.

Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $150,000 from August 20, 2022 through October 4, 2022, and other demobilization fees totaling $15.3 million ~~($9.4~~on a gross basis, $8.9 million net to ~~VAALCO).~~VAALCO Gabon. The Company relinquished control over the FPSO in the fourth quarter of 2022. VAALCO and the owners of the FPSO are negotiating a final settlement of amounts owed to each other and will conclude on the Company’s restricted cash balances associated with the FPSO.

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

Regulatory and Joint Interest Audits and Related Matters

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

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

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

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

~~FSO~~

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

Dividend Policy

On November 3, 2021, the Company announced that the Company’s board of directors adopted a cash dividend ~~policy of an expected $0.0325 per common share per quarter.~~ policy.

On ~~January 28, 2022,~~ February 14, 2023, the ~~Company announced that the Company’s~~Company's board of directors ~~had~~ declared a quarterly cash dividend of ~~$0.0325~~$0.0625 per common share, ~~of common stock,~~ which was paid onMarch ~~18, 2022~~ 31, 2023to stockholders of record at the close of business on ~~February 18, 2022. In April 2022, we~~March 24, 2023. On May 9, 2023, the Company's board of directors declared ~~our intent~~a quarterly cash dividend of $0.0625 per common share to ~~pay a div~~be paid on ~~idend of $0.0325 per~~ ~~share of common stock for the second quarter of 2022 ($0.13 annualized), which is~~ ~~payable~~ June ~~24, 2022~~ 23, 2023to stockholders of record at the close of business on May ~~25, 2022.~~ ~~However, payment~~24,2023.

In connection with the RBL facility, discussed in Note 11, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, the Company may make distributions, buyback shares, or repurchase stock without further approval. In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock. For the three months ended March 31, 2023, no specific approval or waivers were required for the Company to make distributions or repurchase stock.

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

Share Buyback Program

On November 1, 2022, the Company announced that the Company’s board of directors formally ratified and approved a share buyback program. The board of directors also directed management to implement a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations.

Table of Contents

The following table shows the repurchases of equity securities related to the share repurchase program after January 1, 2023 through March 31, 2023:

Period	*Total Number of Shares Purchased*		*Average Price Paid per Share*		*Total Number of Shares Purchased as Part of Publicly Announced Programs*		*Maximum Amount that May Yet Be Used to Purchase Shares Under the Program*
January 1, 2023 - January 31, 2023		350,832	$	4.27		350,832	$	25,502,669
February 1, 2023 - February 28, 2023		326,992	$	4.59		326,992	$	24,003,172
March 1, 2023 - March 31, 2023		303,176	$	4.95		303,176	$	22,503,206
Total		981,000				981,000

The following table shows the repurchases of equity securities related to the share repurchase program after April 1, 2023 throughMay 9, 2023:

~~Other contractual commitments~~

Period	*Total Number of Shares Purchased*		*Average Price Paid per Share*		*Total Number of Shares Purchased as Part of Publicly Announced Programs*		*Maximum Amount that May Yet Be Used to Purchase Shares Under the Program*
April 1, 2023 - April 30, 2023		303,969	$	4.93		303,969	$	21,003,245
May 1, 2023 - May 8, 2023		362,843	$	4.14		362,843	$	19,502,740
Total		666,812				666,812

In ~~June~~connection with the RBL facility, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, the Company may make distributions, buyback shares, or repurchase stock without further approval. In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock. For the three months ended March 31, 2023, no specific approval or waivers were required for the Company to make distributions or repurchase stock.

The actual timing number and value of shares repurchased under the share buyback program will depend on a number of factors, including constraints specified in the Plan, the Company's stock price, general business and market conditions, and alternative investment opportunities. Under the Plan, the Company’s third-party broker, subject to SEC regulations regarding certain price, market, volume and timing constraints, would have authority to purchase the Company’s common stock in accordance with the terms of the Plan.

Merged Concession Agreement

On January 20, 2022, prior to the consummation of the Arrangement, TransGlobe announced a fully executed concession agreement "Merged Concession Agreement" with the Egyptian General Petroleum Corporation (“EGPC”) that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $15.0 million and signature bonus of $1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022. On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million. In accordance with the Merged Concession, the Company agreed to substitute the February 2023 payment and issue a $10.0 million credit against receivables owed to it from EGPC. The Company will make three further annual equalization payments of $10.0 million each beginning February 1, 2024 until February 1, 2026. VAALCO recorded modernization payment liabilities of $26.3 million at March 31, 2023. On the unaudited condensed consolidated balance sheet, $9.4 million of the modernization payment liability was recorded in the line item "Accrued liabilities and other" and $17.0 million was recorded in "Other long-term liabilities".

Table of Contents

The Company also has minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date") for a total of $150 million commencing on the Merged Concession Effective Date"). Through March 31, 2023, all investments have exceeded the five-year minimum $50 million threshold and any excess carries forward to offset against subsequent five-year commitments.

As the Merged Concession Agreement is effective as of February 1, 2020, there will be effective date adjustment owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date. In accordance with GAAP, the Company has recognized a receivable in connection with the effective date adjustment of $67.5 million as of October 13, 2022, based on historical realized prices. However, the cumulative value to be received as a result of the effective date adjustment is currently being finalized with the EGPC and could result in a range of outcomes based on the final price per barrel negotiated. As of March 31, 2023, $50.3 million of the original $67.5 million receivable is recorded on the unaudited condensed consolidated balance sheet in Receivables-Other, net.

Government Related Receivables

Under the Article 35 of the Etame PSC, the Company can be required to contribute to meeting the domestic market needs of Gabon by delivering to the Government, or another entity designated by the Government, an amount of its crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In October 2021,the Company was notified by the Government to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. In exchange, the Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered.

Since the crude oil produced by the Company is not compatible with the crude oil requirements of the refinery, the Company entered into ~~a short-term agreement with an affiliate of Borr Drilling Limited~~two contracts (buy/sell arrangements) to ~~drill a minimum of 3 wells with options~~fulfill its domestic market needs obligation under the Etame PSC. One contract is to ~~drill additional wells. Upon completion~~purchase oil from another provider (currently Perenco – the supplier) that produces the compatible oil to meet the needs of the ~~ETBSM 1HB-ST2~~refinery and another contract with the refinery itself (currently Sogara -the buyer and state designee) to deliver the crude oil to the Government.

In November 2022, a receivable from Sogara became past due and the Company has not received payments from the refinery since November 2022. At March 31, 2023 the amount due to the Company from the refinery is $20.3 million. The Company is in ongoing discussions with the Ministry of the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to the realization of the past due balances related to both the receivable from the refinery as well as past due VAT receivable amounts owed to the ~~commitment~~Company. The Company expects to ~~Borr Drilling Limited~~recover the full amount of receivables owed to it for both the VAT receivable and receivable under the oil supply arrangement, but the terms of recovery have not been finalized.

11. DEBT

As of March 31, 2023 and December 31, 2022, the Company had no outstanding debt.

RBL Facility

On May 16, 2022, the Borrower entered into the Facility Agreement by and among the Company, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C., as security agent, and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $50.0 million (the “Initial Total Commitment”). In addition, subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million (any such increase, an “Additional Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be ~~satisfied.~~reduced by $6.25 million.

Table of Contents

The Facility provides for determination of the borrowing base asset based on the Company’s proved producing reserves in Gabon and a portion of the Company's proved undeveloped reserves in Gabon. The borrowing base is determined and re-determined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.

~~11. LEASES~~

Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00% until the third anniversary of the Facility Agreement or (ii) 6.25% from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).

Pursuant to the Facility Agreement, the Company shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.

The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed 3.0x and (ii) consolidated cash and cash equivalents shall not be lower than $10.0 million. As of March 31, 2023, the Company's borrowing base was $50.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. With regard to the requirement that the Company deliver its fiscal year 2022 annual financial statements to Glencore within 90 days of the end of each fiscal year, the Company requested and received an extension until April 17, 2023. The Company delivered the annual financial statements, along with its covenant compliance certificate to Glencore on April 11, 2023. At March 31, 2023, the Company was in compliance with all other debt covenants and had no outstanding borrowings under the facility.

The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).

Deferred financing costs incurred in connection with securing the Facility were $1.8 million, ($2.1 million net of accumulated amortization of $0.3 million) which is carried in the accompanying unaudited condensed consolidated balance sheets in the line item "Other long-term assets" and is amortized on a straight-line basis, which approximates the effective interest method, over the term of the Facility and included in interest expense in the accompanying unaudited condensed consolidated statements of operations and comprehensive income.

ATB Facility

In connection with the Arrangement with TransGlobe in October 2022, and prior to the effective time of the Arrangement, TransGlobe repaid in full all outstanding obligations and liabilities owed under TransGlobe’s credit facility with ATB Financial (the "ATB Facility"), representing approximately Canadian $4.1 million. On January 5, 2023, the ATB Facility was formally closed. Termination of the ATB Facility will not affect the Company's $50.0 million senior secured reserve-based revolving credit facility with Glencore.

12. LEASES

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

Practical Expedients –

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

(1)

Represents depreciation and interest associated with financing leases.

(2)

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

(3)

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

Three Months Ended March 31,
2022
2021
Lease cost:
(in thousands)
Finance lease cost ⁽¹⁾
$
66
$
—
Operating lease cost
4,196
4,390
Short-term lease cost ⁽²⁾
1,014
794
Variable lease cost ⁽³⁾
1,338
1,434
Total lease expense
6,614
6,618
Lease costs capitalized
772
—
Total lease costs
$
7,386
$
6,618
Other information:
Cash paid for amounts included in the measurement of lease liabilities:
2022
2021
Operating cash flows attributable to finance leases
$
—
$
—
Weighted-average remaining lease term
5.42 years
—
Weighted-average discount rate
3.54%
—
Operating cash flows attributable to operating leases
$
6,551
$
4,773
Weighted-average remaining lease term
0.73 years
1.5 years
Weighted-average discount rate
5.83%
6.09%

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

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

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

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

	*Three Months Ended March 31,*
	*2023*		*2022*
	*(in thousands)*
Finance lease cost	$	2,625	$	39
Production expense		1,286		3,838
General and administrative expense		46		16
Lease costs billed to the joint venture owners		2,368		3,002
Total lease expense		6,325		6,895
Lease costs capitalized		31		491
Total lease costs	$	6,356	$	7,386

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

Table of Contents

The following table describes the future maturities of the Company’s lease liabilities at March 31, ~~2022:~~2023:


	Operating Leases		Finance Leases		*Operating Leases*		*Finance Leases*
Year	(in thousands)				*(in thousands)*
2022	$	6,397	$	311
2023		371		368	$	1,829	$	10,377
2024		197		368		672		13,759
2025		33		368		33		15,559
2026						—		16,156
2027						—		15,023
Thereafter		—		537		—		51,561
		6,998		1,952		2,534		122,435
Less: imputed interest		108		201		127		35,058
Total lease liabilities	$	6,890	$	1,751	$	2,407	$	87,377

Under the joint operating agreements, other joint venture owners are obligated to fund ~~$5.3~~$51.5 million of the ~~$9.0~~$125.0 million in future lease liabilities.

~~12.~~

13. ASSET RETIREMENT OBLIGATIONS

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

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

*(in thousands)*	*As of March 31, 2023*			*As of December 31, 2022*
Beginning balance	$	42,001		$	40,694
Accretion		556			1,958
Additions		—			6,134
Revisions		79			(43	)
Settlements		(123	)		(6,577	)
Foreign currency gain (loss)		74			(165	)
Ending balance	$	42,587		$	42,001

Accretion is recorded in the line item “Depreciation, depletion and amortization” onin the unaudited condensed consolidated statements of ~~operations.~~operations and comprehensive income.

In connection with the TransGlobe Arrangement in October 2022, as discussed in Note 3, the Company added $6.1 million of ARO for the future abandonment and reclamation costs of the Canadian assets. The Egypt concessions have no ARO.

With relation to the end of the FPSO contract in October 2022, the Company incurred decommissioning settlement fees totaling $6.6 million previously recorded in the asset retirement obligations and included on the consolidated statements of cash flows in the line item, "Cash settlements paid on asset retirement obligations".

The Company is required under the Etame PSC for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was prepared in November 2021. At December 31, 2021, associated with the study, the Company recorded an upward revision of $7.2 million to the asset retirement obligation primarily as a result of increased costs expected with the abandonment of the Etame Marin block and a change in the expected timing of the abandonment costs associated with the termination of the FPSO charter. As a result of the expected timing of the ~~abandonment~~end of the FPSO contract, included in ~~accrued~~the line item "Accrued liabilities and other" in the unaudited condensed consolidated balance sheet is ~~$6.8~~$0.3 million of costs associated with the retirement obligation as of March 31, ~~2022.~~2023.

In Egypt, under model concession agreements and the Fuel Material Law, liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process. While the current risk to the Company of becoming liable for decommissioning liabilities in Egypt is low, future changes to legislation could result in decommissioning liabilities in Egypt. Any increase in Egyptian decommissioning liabilities could adversely affect the Company's financial condition.

Table of Contents

~~13. SHAREHOLDERS’ EQUITY~~In relation to petroleum wells, under good oilfield practices, the contractor is responsible for decommissioning non-producing wells under a decommissioning plan approved by EGPC during the life of the concession agreement. If EGPC agrees that a producing well is not economic, then the contractor may be responsible for decommissioning the well under an EGPC approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes. As EGPC has discretion on decommissioning wells, there is a risk that the Company could incur well decommissioning costs. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism. At December 31, 2022, no asset retirement obligation is recorded associated with the Egypt PSCs.

The Company provides for asset retirement obligations on all of its Canadian operations based on current legislation and industry operating practices. The estimated present value of the asset retirement obligation is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The estimated ARO liability for Canada includes assumptions of actual costs to abandon and/or reclaim wells and facilities, the time frame in which such costs will be incurred, as well as using inflation factors and discount rates in order to calculate the amount of the ARO liability.

14. SHAREHOLDERS’ EQUITY

Common stock

On October 13, 2022, in connection with the closing of the Arrangement, (i) the total number of authorized shares of common stock of the Company was increased from 100 million shares to 160 million shares and (ii) VAALCO issued approximately 49.3 million shares to TransGlobe's shareholders.

Preferred stock –

Authorized preferred stock consists of 500,000 shares with a par value of $25 per share. ~~NaN~~No shares of preferred stock were issued and outstanding as of March 31, ~~2022 or December 31, 2021.~~2023.

Treasury stock –

On November 1, 2022, the Company announced that the board of directors formally ratified and approved a share buyback program. The Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations. See Note 10 for further discussion.

The below table shows the repurchases of the Company's equity securities during the three months ended March 31, 2023:

Period	*Total Number of Shares Purchased*		*Average Price Paid per Share*		*Total Number of Shares Purchased as Part of Publicly Announced Programs*		*Maximum Amount that May Yet Be Used to Purchase Shares Under the Program*
January 1, 2023 - January 31, 2023		350,832	$	4.27		350,832	$	25,502,669
February 1, 2023 - February 28, 2023		326,992	$	4.59		326,992	$	24,003,172
March 1, 2023 - March 31, 2023		303,176	$	4.95		303,176	$	22,503,206
Total		981,000				981,000

Table of Contents

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

Although these withheld shares are not issued or considered common stock repurchases under the Company’s stock repurchase program, they are treated as common stock repurchases in ~~our~~the Company's financial statements as they reduce the number of shares that would have been issued upon vesting. See Note 1415 for further discussion.

~~14.~~

15.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~~“2020 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At March 31, ~~2022, 6,694,501~~2023, under the 2020 Plan, 3,989,458 shares were available for future ~~grants under the 2020 Plan.~~grants.

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

As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the three months ended March 31, 2023, the Company settled in cash $0.2 million for stock appreciation rights and received $0.3 million for stock option exercises. During the three months ended March 31, 2022, the Company settled in cash $0.2 million for stock appreciation rights and received $0.2 million for stock option exercises.~~During the three months ended March 31, 2021, the Company settled in cash $0.9 million for stock appreciation rights and received $0.3 million for stock option exercises~~

	*Three Months Ended March 31,*
	*2023*			*2022*
	*(in thousands)*
Stock-based compensation - equity awards	$	675		$	404
Stock-based compensation - liability awards		(26	)		1,018
Total stock-based compensation	$	649		$	1,422

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

Table of Contents

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~~three-year~~-year period, vesting in three equal parts on the anniversaries from the date of grant, and may contain performance hurdles.

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

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

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

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

During the three months ended March 31, 2022 ~~and 2021,~~, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo. No options were granted in the first quarter of 2023.


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

Stock option activity associated with the Monte Carlo model for the three months ended March 31, ~~2022~~2023 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, 2023		444		$	3.98
Granted		—			—
Exercised		(74	)		(1.68	)
Unvested shares forfeited		—			—
Vested shares expired		—			—
Outstanding at March 31, 2023		370		$	4.40			8.30	$	414
Exercisable at March 31, 2023		166		$	3.91			8.15	$	224

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

Table of Contents

Stock option activity associated with the Black-Scholes model for the three months ended March 31, ~~2022~~2023 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, 2023		387		$	1.86
Granted		—			—
Exercised		(99	)		(1.50	)
Unvested shares forfeited		—			—
Vested shares expired		—			—
Outstanding at March 31, 2023		288		$	1.98			0.81	$	732
Exercisable at March 31, 2023		288		$	1.98			0.81	$	732

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

~~During the three months ended March 31, 2022, 28,761 shares were added to treasury as~~As a result of tax withholding on options ~~exercised.~~exercised, 22,027 shares were added to treasury during the three months ended March 31, 2023.

Restricted shares

Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three~~three-year~~-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)~~ (50) weeks following the date of grant). ~~In March 2022, the Company issued 353,424 shares of service-based restricted stock to employees, with a grant date fair value of $6.41 per share.~~ The vesting of ~~these shares~~the restricted stock is dependent upon, among other things, the employees’ and directors’ continued service with the Company.

The following is a summary of activity for the three months ended March 31, ~~2022:~~2023:

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

	*Restricted Stock*			*Weighted Average Grant Date Fair Value*
	*(in thousands)*
Non-vested shares outstanding at January 1, 2023		665		$	4.59
Awards granted		—			—
Awards vested		(205	)		4.82
Awards forfeited		—			—
Non-vested shares outstanding at March 31, 2023		460		$	4.49

During the three months ended March 31, ~~2022, 35,232~~2023, 55,600 shares were added to treasury as a result of tax withholding on the vesting of restricted shares.

In connection with the Arrangement with TransGlobe and pursuant to the Arrangement Agreement, at the effective time of the Arrangement, certain awards previously issued to TransGlobe’s key employees and board members who continued their relationship as employees or board members of VAALCO following the Arrangement, continue to be governed by the applicable TransGlobe plan, provided that each such applicable plan has been amended to provide that VAALCO common stock shall be issuable in lieu of cash or TransGlobe common stock with respect to TransGlobe’s deferred share units (“DSU”s), performance share units (“PSU”s) and restricted stock units (“RSU”s), in each case, based on the exchange ratio in the Arrangement. For the PSUs that remained outstanding following the effective time of the Arrangement, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200% for PSUs granted in 2020 and 2021 and 64.4% for PSUs granted in 2022.

Table of Contents

RSUs were issued to directors, officers and employees of TransGlobe in the ordinary course of business prior to the Arrangement. Each RSU vests annually over a three-year period. On December 16, 2022, Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. The following is a summary of RSU activity for the three months ended March 31, 2023:

	*Restricted Stock*			*Weighted Average Conversion Date Fair Value*
	*(in thousands)*
Non-vested shares outstanding at January 1, 2023		383		$	4.27
Awards granted		—			—
Awards vested		(121	)		4.27
Awards forfeited		(23	)		4.27
Non-vested shares outstanding at March 31, 2023		239		$	4.27

During the three months ended March 31, 2023, 45,186 shares were added to treasury as a result of tax withholding on the vesting of RSU’s.

PSUs are similar to RSUs except that they originally contained a performance factor affecting the vesting percentage. For the PSUs that remained outstanding following the effective time of the Arrangement, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200% for PSUs granted in 2020 and 2021; and 64.4% for PSUs granted in 2022. All PSUs granted vest on the third anniversary of their grant date. On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. The following is a summary of PSU activity for the three months ended March 31, 2023:

	*Restricted Stock*			*Weighted Average Conversion Date Fair Value*
	*(in thousands)*
Non-vested shares outstanding at January 1, 2023		690		$	4.27
Awards granted		—			—
Awards vested		(134	)		4.27
Awards forfeited		(36	)		4.27
Non-vested shares outstanding at March 31, 2023		520		$	4.27

During the three months ended March 31, 2023, 64,256 shares were added to treasury as a result of tax withholding on the vesting of PSU’s.

DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from theCompany's Board of Directors. On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. At March 31, 2023, approximately 460,000 DSUs are vested but not distributed. No grants, vestings, distributions or forfeitures occurred in the first quarter of 2023 related to DSUs.

Stock appreciation rights ~~(“SARs”~~(“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.

Table of Contents

During the three months ended March 31, ~~2022,~~2023, the Company did 0tnot grant SARs to employees or directors.

SAR activity for the three months ended March 31, ~~2022~~2023 is provided below:

	*Number of Shares Underlying SARs*			*Weighted Average Exercise Price Per Share*		*Weighted Average Remaining Contractual Term*		*Aggregate Intrinsic Value*
	*(in thousands)*					*(in years)*		*(in thousands)*
Outstanding at January 1, 2023		202		$	1.87
Granted		—			—
Exercised		(63	)		0.86
Unvested SARs forfeited		—			—
Vested SARs expired		—			—
Outstanding at March 31, 2023		139		$	2.33		0.92	$	304
Exercisable at March 31, 2023		139		$	2.33		0.92	$	304

Number of Shares Underlying SARs
Weighted Average Exercise Price Per Share
Term
Aggregate Intrinsic Value
(in thousands)
(in years)
(in thousands)
Outstanding at January 1, 2022
362
$
1.81
Granted
0
—
Exercised
(59)
1.41
Unvested SARs forfeited
—
—
Vested SARs expired
—
—
Outstanding at March 31, 2022
303
$
1.89
1.75
$
1,402
Exercisable at March 31, 2022
237
$
1.94
1.65
$
1,086

Other Benefit Plans

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

~~15.~~16. INCOME TAXES

VAALCO and its domestic subsidiaries file a consolidated U.S. income tax return. Certain foreign subsidiaries also file tax returns in their respective local ~~jurisdictions.~~jurisdictions that include Canada, Egypt, Equatorial Guinea and Gabon.

Income taxes attributable to continuing operations for the three months ended March 31, ~~2022,~~ 2023 and ~~2021~~2022 are attributable to foreign taxes payable in Gabon and Egypt, as well as income taxes in the U.S.

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

Table of Contents

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

The Company’s effective tax rate for the three months ended March 31, ~~2022~~ 2023 and ~~2021,~~2022, excluding the impact of discrete items, was ~~67.9%~~60.96% and ~~(64%)~~67.9%, respectively. ~~For the three months ended March 31, 2022, the Company’s overall effective tax rate was impacted by non-deductible items associated with operations, and a change in valuation allowance.~~ The total tax expense for the three months ended March 31, ~~2022~~ 2023, includes a discrete ~~adjustment for the release~~amount of ~~$12.7~~$4.6 million ~~of valuation allowance~~primarily related to adjustments made as a result of ~~an increase in forecasted future earnings.~~changes to oil price adjustments. For the three months ended March 31, 2023, the current tax expense of $12.3 million includes a $3.2 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding that impact, current income taxes were an expense of $9.1 million for the period. For the three months ended March 31, 2022, the current tax expense of $ 5.7 million includes a $3.1 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $2.6 million for the ~~period. For the three months ended~~ period

As of March 31, 2021, the current tax expense of $3.4 million includes a $0.5 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $2.9 million for the period.

~~As of March 31, 2022,~~2023, the Company had 0no 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.

‎

17.OTHER COMPREHENSIVE INCOME

The Company’s other comprehensive loss was $0.1 million for the three months ended March 31, 2023. The functional currency of TransGlobe Energy Corporation is the Canadian Dollar. All of the Company’s other comprehensive income arises from the currency translation of TransGlobe Energy Corporation to USD.

The components of accumulated other comprehensive income are as follows:

	*Currency Translation Adjustments*
	*(in thousands)*
Balance at December 31, 2022	$	1,179
Accumulated other comprehensive income (loss) before reclassifications		(125	)
Balance at March 31, 2023	$	1,054

Table of Contents

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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

●

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

●

our ability to remediate our material weaknesses;

●

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

●

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

●

future capital requirements;

●

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

●

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

●

the ability of the BWE Consortium to successfully execute its business plan;

●

our ability to attract capital or obtain debt financing arrangements;

●

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

●

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

●

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

●

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, natural gas and NGLs reserves;

●

currency exchange rates and regulations;

●

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

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

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

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

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

~~future capital requirements;~~

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

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

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

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

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

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

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

~~the impact of competition;~~

~~our ability to identify and complete complementary opportunistic acquisitions;~~

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

~~weather conditions;~~

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

~~currency exchange rates and regulations;~~

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

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

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

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

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

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

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

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

~~our ability to enter into new customer contracts;~~

Table of Contents

●

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 ultimate resolution of our negotiations with the Egyptian General Petroleum Corporation ("EGPC") relating to the Effective Date Adjustment (as defined below);
	●	the availability and cost of seismic, drilling and other equipment;

●

difficulties encountered in measuring, transporting and delivering crude oil, natural gas and NGLs to commercial markets;

●

timing and amount of future production of crude oil, natural gas and NGLs;

●

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

●

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

●

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, natural gas and NGLs properties.

~~changes in customer demand and producers’ supply;~~

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

~~actions by our joint venture owners;~~

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

~~the outcome of any governmental audit; and~~

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

The information contained in this Quarterly Report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, ~~2021~~2022 (“~~2021~~2022 Form 10-K”), identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Quarterly Report and the ~~2021~~2022 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Quarterly Report.

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

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

INTRODUCTION

VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude ~~oil.~~oil, natural gas and NGLs. As operator, we have production operations and conduct exploration ~~and development~~ activities in Gabon, West ~~Africa.~~Africa, Egypt and Canada. 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,~~Financial Statements, we have discontinued operations associated with our activities in Angola, West ~~Africa.~~Africa and Yemen.

Table of Contents

RECENT DEVELOPMENTS

~~Marine Construction~~

Dividend Policy

On February 14, 2023, our board of directors increased our quarterly cash dividend policy to an expected $0.0625 per common share per quarter, commencing in the first quarter of 2023 and concurrently declared a quarterly cash dividend of $0.0625 per common share that was paid on March 31, 2023 to stockholders of record at the close of business on March 24, 2023. On May 9, 2023 our board announced a cash dividend of $0.0625 per share of common stock to be paid on June 23, 2023 to stockholders of record at the close of business on May 24, 2023.

Share Buyback Program

On November 1, 2022, VAALCO announced that its board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with our business combination with TransGlobe. The board of directors also directed management to implement the 10b5-1 Plan to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Exchange Act. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using cash on hand and cash flow from operations.

The actual timing number and value of shares repurchased under the share buyback program will depend on a number of factors, including constraints specified in the Plan, VAALCO's stock price, general business and market conditions, and alternative investment opportunities. Under the Plan, our third-party broker, subject to SEC regulations regarding certain price, market, volume and timing constraints, has authority to purchase VAALCO common stock in accordance with the terms of the Plan.

TransGlobe Merger

On October 13, 2022, VAALCO and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the issued and outstanding TransGlobe common shares pursuant to the Arrangement and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement.

Additionally, prior to the effective time of the Arrangement, TransGlobe repaid outstanding obligations and liabilities owned under TransGlobe’s credit facility with ATB Financial, representing approximately C$4.1 million. On December 19, 2022, TransGlobe, as an indirect wholly-owned subsidiary of VAALCO, voluntarily delivered a notice of termination to ATB Financial relating to the ATB Facility. As of December 31, 2022, no amounts were drawn on the revolving loan facility. On January 5, 2023, the ATB Facility was formally closed.

The actual impact of the Arrangement Agreement was an increase to “Crude oil, natural gas and NGLs sales” of $43.7 million and $9.7 million of “Net income” in the condensed consolidated statements of operations and comprehensive income for ~~Subsea Reconfiguration~~the three months ended March 31, 2023.

Entry into a Facility Agreement

On ~~March 17,~~May 16, 2022, VAALCO Gabon ~~SA (“VAALCO Gabon”~~(Etame), Inc. (the “Borrower”), a wholly owned subsidiary of ~~the Company,~~VAALCO, entered into a facility agreement (the “Facility Agreement”) by and among VAALCO, VAALCO Gabon, SA (“VAALCO Gabon” and, together with VAALCO, the “Guarantors”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in an ~~Agreement~~aggregate maximum principal amount of up to $50.0 million. Subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million (any such increase, an “Additional Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million. See “Capital Resources and Liquidity – RBL Facility Agreement” for more information regarding the Facility.

Table of Contents

Recent Operational Updates

Gabon

VAALCO completed its 2021/2022 drilling campaign in the fourth quarter of 2022. We are currently evaluating locations and planning for the ~~Provision of Subsea Construction and Installation Services (the “Marine Construction Agreement”) with DOF Subsea Canada Corp. (“DOF Subsea”),~~next drilling campaign at Etame that is expected to ~~support the subsea reconfiguration~~occur in ~~connection with the replacement of the existing FPSO vessel with~~2024. In October 2022, VAALCO successfully completed its transition to a Floating Storage and Offloading vessel (“FSO”) atand related field reconfiguration processes. This project provides a low cost FSO solution that increases the Company’s Etame Marin field offshore Gabon. Pursuant to the Marine Construction Agreement, DOF Subsea agreed to, among other things, provide all personnel, crew and equipment necessary to assist in the reconfiguration ofstorage capacity for the Etame ~~field subsea infrastructure~~block. The Company will continue to ~~accommodate all field~~focus on operational excellence, including production uptime and enhancement in 2023 to minimize decline until the flow to the FSO, which is currently under conversion, including (i) assistance with retrieval of over 5,000 meters of new flexible pipelines from a manufacturing facility in the United Kingdom, transporting the pipelines to Gabon and installing the pipelines in the Etame field, (ii) performing the retrieval and relocation of existing in-field flowlines and umbilicals to accommodate the reconfigured field development plan and (iii) assistance in the connection of new risers to the FSO (collectively, the “Services”). Pursuant to the Marine Construction Agreement, DOF Subsea will provide an offshore construction vessel to facilitate the performance of the Services. The Marine Construction Agreement provides that the Services will commence in early July 2022 and be completed by the end of September 2022, subject to certain conditions therein. As consideration for the Services provided to the Company, the Company agreed to pay DOF Subsea certain fixed fees upon the completion of the achievement of Service-related milestones, as well as a day rate, subject to certain conditions, as set forth in the Marine Construction Agreement.

~~Recent Operational Updates~~

~~Provisional Award of Two Offshore Blocks in Gabon~~

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

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

~~Charter Agreement for the Floating Storage and Offloading Unit~~

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

~~2021/2022 Drilling Campaign~~

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

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

~~We estimate the range of~~

The cost of the 2021/2022 drilling program with four wells ~~to be between $117.0~~and two workovers was $180 million, ~~to $143.0 million gross,~~ or ~~$74.0 million to $91.0~~$114 million, net to VAALCO’s ~~63.6%~~ participating ~~interest~~interest.

For the three months ended March 31, 2023, all wells were online from the end of 2022 as the gas lift compression system was successfully commissioned. This gas lift compression system increased the production and the reliability of two subsea wells positively, impacting our volumes for the three months ended March 31, 2023.

The focus during the first quarter of 2023 was continued production optimization of the new flow line configurations at the Etame Facility, as all production transits through the Etame platform for final processing before being pumped to the FSO. Since the field reconfiguration in 2022, a better understanding of the field’s operating parameters has resulted in a more efficient and cost effective flow assurance program. Combining this with ~~about $26 million~~chemical injection optimization and pipeline pigging adjustments both on frequency of pigging and flow path targeting has increased production and provided more stable operations resulting in lower downtime.

Preventative maintenance activities returned to ~~about $31 million gross~~levels prior to the field reconfiguration, as the focus came back to steady state operation following project completion.

Egypt

We continued to use the EDC-64 rig in the Eastern Desert drilling campaign. We completed the Arta 77Hz horizontal well drilling at the beginning of 2023 and released the rig on January 11, 2023. The well is flowing at approximately 200 bopd with minimal water. We expect cleanup on this well to continue for an extended period of time. This delayed the 2023 drilling campaign. However, during the remainder of the quarter, we drilled and cased five development wells, (East Arta 53 ("EA-53"), K-81, K-79, Arta-80 Red Bed, and Arta 81 Red Bed).

The EA-53 development well was drilled to a total depth of 1,279 meters targeting Red Bed reservoirs in the East Arta Field. The well was fully logged and evaluated. The Red Bed reservoir has an estimated 4.5 meters of net oil pay. The lower most Red Bed reservoir was perforated in the EA-53 well and is producing 100% water which was unexpected given that the East Arta 21 well's current production is at a 67% water cut and the East Arta 39 well's production is at an 80% water cut. There is a plan to fracture stimulate the EA-53 well to try and get oil production.

The K-81 well was drilled as vertical development well with ASL-D reservoir as the primary target and ASL-E reservoir as a secondary target. The well spudded on February 2, 2023, and reached total depth ("TD") on February 12, 2023 at a depth of 1,662m in the ASL-F reservoir. Log analysis indicated the presence of 21m of net pay in both the ASL-D and ASL-E sands. The well was perforated in the ASL-E zone over the interval from 1,503 to 1,507m MD. The well went online March 5, 2023, at an initial production of 504 bopd.

Table of Contents

The K-79 well was drilled as a vertical development well with the ASL-D reservoir as the primary target, and the ASL-B and ASL-E reservoirs as secondary targets. The well spudded on February 21, 2023, and reached TD on March 1, 2023 at a depth of 1,739 m in the ASL-F reservoir. Log analysis indicates the presence of 57.9m net pay, 9m in the ASL-D reservoir, 31 m in the ASL-B reservoir and 13.7m in the ASL-A sands. The well perforated in the ASL-B1 and B2 zones from 1,273 to 1,285m and 1,302 to 1,308m. Initial production commenced on March 15, 2023 at 192 bopd.

The Arta-80 development well reached its primary objective of the Red Bed reservoir approximately 24.4 meters higher than prognosis and encountered a total of 10 meters of net pay. The well spudded on March 10,2023 and reached TD on March 15,2023 at a depth of 1,250 meters in the Thebes Formation. Open hole log evaluation indicated the presence of 10.5 meters of net pay in the Red Bed primary reservoir. The top 9.5 meters of the Red Beds were perforated from 1,105 to 1,115 meters and began to produce on March 25, 2023 with initial production of 403 bopd.

The Arta-81 development well spud on March 21, 2023 and reached TD on March 25, 2023 at a depth of 1,264 meters within the Thebes formation. It achieved the primary objective 4.2 meters higher than prognosis and encountered a total of 9 meters of net pay in the Red Beds reservoir. The well was perforated in the top 7.9 meters of the Red Bed reservoir (1,133-1,423 meters) and began to produce on April 6, 2023 with an initial production of 317 bopd.

The HE-4 appraisal well was drilled to a total depth of 1,850m in the Bakr sand formation, reaching its primary objective of penetrating oil-bearing sands in the ASL-B formation. The well spudded on April 2, 2023 and reached TD on April 9, 2023. Open hole log evaluation indicated 8.5 meters of net pay across 3 sand zones in the ASL-B including a new sand formation not seen in offset wells to the north. The well was perforated from 1,590-1,594 meters in the lowermost sand and was put on production on April 19, 2023. Current production is approximately 180 bopd (field estimate) at 50% water cut.

The HE-5INJ injection well is planned downdip of HE-1X, HE-2 and the proposed HE-3 well (to be drilled after HE-5INJ). The reservoirs in this pool are relatively thin and pressure data indicates depletion. Injecting into the reservoir will support pressure and should improve the estimated ultimate recovery of the producing ASL-B zones.

The SGZ-6X well in the South Ghazalat concession in the Western Desert remains shut-in. Recomplete work on the well is underway to put it back on production to retain the acreage. Intervention planning was completed during the first quarter of 2023 and operations have now started in order to resume production from the Western Desert.

Canada

Early in 2023, two wells, the 1Q100/04-10-29-03W5 and the 4-19-29-3W5, were tied in. Initially, the tie-in had been scheduled for late 2022 but due to weather and contractor delays, these were moved into 2023 (1Q100/04-10-29-03W5 /4-19-29-3W5). Both wells are now online and producing.

The 2023 drilling campaign commenced in January 2023 with the drilling of 12-12-30-4W5, spud on January 28, 2023. The well was drilled to a total depth of 6,713 meters. The second well of the program, 16-30-29-3W5, was spud on February 22, 2023, and drilled to total depth of 4,403 meters. The 2 wells were completed between late March and early April with good oil shows. Both wells are currently being equipped for production and are expected online in ~~2021, or about $16 million~~May 2023 with a significant reduction in historical cycle times compared to ~~$20 million net to VAALCO.~~previous wells.

~~Acquisition of Additional Working Interest at~~

ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

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

~~ACTIVITIES BY ASSET~~

~~Gabon~~

~~Offshore – Etame Marin Block~~

Development and Production

We operate the Etame Marin Block on behalf of a consortium of companies. As of March 31, ~~2022,~~2023, production operations in the Etame Marin block included ~~eleven~~fifteen platform wells, plus ~~three~~two subsea wells tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery and processing ~~storage and ultimately offloading~~at the Etame platform. From the Etame platform, the crude oil ~~from~~is pumped through a riser system to the FSO where it is stored and ultimately offloaded. The leased ~~FPSO~~FSO is anchored to the seabed on the block. WeThe Etame field currently ~~have fourteen~~has a combined total of seventeen producing wells. ~~The FPSO has production limitations of approximately 25,000 barrels of oil per day and 30,000 barrels of total fluids per day.~~ During the three months ended March 31, ~~2022~~2023 and ~~2021,~~2022, production from the block was ~~1,416~~1,603 MBbls ~~(725~~(820 MBbls, net) and ~~1,253~~1,416 MBbls ~~(466~~(725 MBbls, net), respectively, as discussed below in “~~Results~~“Results of ~~Operations~~”Operations”.

~~Equatorial Guinea~~

Table of Contents

~~Our~~Egypt

In Egypt, as of March 31, 2023, our interests are spread across two regions: the Eastern Desert, which contains the West Gharib, West Bakr and North West Gharib merged concessions, and the Western Desert, which contains the South Ghazalat concession. Both of our Egyptian blocks are PSCs among the Egyptian General Petroleum Corporation (“EGPC”), the Egyptian government and us. We are the operator and have a 100% working interest ~~will increase~~in both PSCs. During the three months ended March 31, 2023, production from the Eastern Desert was 903 MBbls (616 MBbls, net) as discussed below in “Results of Operations”.

The SGZ-6X well in the South Ghazalat concession in the Western Desert remains shut-in.

Canada

In Harmattan, Canada, we own production and working interests in the Cardium light oil and Mannville liquids-rich gas assets. This property produces oil and associated natural gas from the Cardium and Viking zones and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 1,200 to ~~45.9% once~~2,600 meters. All gas is delivered to a third party non-operated gas plant for processing. During the ~~EG MMH approves a new amendment~~three months ended March 31, 2023, production from our Canadian assets was 239 MBoe to ~~the production sharing contract.~~ our working interest (211 MBoe, net) as discussed below in “Results of Operations”.

Equatorial Guinea

As of March 31, ~~2022,~~2023, 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~~In February of ~~a standalone~~2023, we acquired an additional 14.1% participating interest, increasing VAALCO’s participating interest in the Block to 60.0%. This increase of 14.1% participating interest increases our future payment to GEPetrol to $6.8 million at first commercial production ~~development opportunity~~of the Block. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March 2023 with this updated participating interest, and execution of the Venus ~~discovery on Block P. We~~development plan has been initiated. VAALCO as operator, is in the process of working through the project charter and timing of key milestones. In addition, there are ~~now proceeding to a field development concept and will work closely with~~some minor changes required by the ~~other~~Joint Operating Agreement that require final ratification by the joint ~~venture owners to complete this over the coming months.~~ venture.

The Block P production sharing contract ("PSC") provides for a development and production period of 25 years from the date of approval of a development and production ~~plan.~~

Block P not associated with the Block P - Venus development.

DISCONTINUED ~~OPERATIONS-ANGOLA~~OPERATIONS - ANGOLA AND YEMEN

In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“PSA”). Our working interest is 40%, and we carried Sonangol P&P, for 10% of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P. that we were withdrawing from the PSA. Further to our decision to withdraw from Angola, we have closed our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the Financial Statements for all periods presented. See Note 3 to the Financial Statements. For the three months ended March 31, 2023 and 2022, ~~and 2021,~~ the Angola segment did not have a material impact on ~~the Company’s~~our financial position, results of operations, cash flows and related disclosures.

As part of the Arrangement with TransGlobe, we acquired TG Holdings Yemen Inc. who previously owned TransGlobe's interests in four PSAs in Yemen: Block 32, Block 72, Block 75 and Block S-1. In January 2015, TransGlobe relinquished its interests in Block 32 and Block 72 in Yemen (effective dates of March 31, 2015 and February 28, 2015, respectively), and in October 2015 TransGlobe sold its subsidiary that held interests in Block 75 and Block S-1. The operating results of the Yemen segment have been classified as discontinued operations for all periods presented in our consolidated statements of operations and comprehensive income. Our segregated the cash flows attributable to the Yemen segment from the cash flows from continuing operations for all periods presented in our consolidated statements of cash flows. For the three months ended March 31, 2023, the Yemen segment did not have a material impact on our financial position, results of operations, cash flows and related disclosures.

Table of Contents

CAPITAL RESOURCESAND LIQUIDITY

Cash Flows

Our cash flows for the three months ended March 31, ~~2022~~2023 and ~~2021~~2022 are as follows:

	Three Months Ended March 31,
	2023			2022			Increase (Decrease) in 2023 over 2022
	*(in thousands)*
Net cash provided by operating activities before changes in operating assets and liabilities	$	32,803		$	27,859		$	4,944
Net change in operating assets and liabilities		9,216			(28,599	)		37,815
Net cash provided by (used in) continuing operating activities		42,019			(740	)		42,759
Net cash used in discontinued operating activities		(13	)		(18	)		5
Net cash provided by (used in) operating activities		42,006			(758	)		42,764

Net cash used in investing activities		(27,700	)		(23,148	)		(4,552	)

Net cash used in financing activities		(13,539	)		(2,118	)		(11,421	)
Effects of exchange rate changes on cash		(309	)		—			(309	)
Net change in cash, cash equivalents and restricted cash	$	458		$	(26,024	)	$	26,482

Three Months Ended March 31,
2022
2021
Increase (Decrease) in 2022 over 2021
(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities
$
26,407
$
13,453
$
12,954
Net change in operating assets and liabilities
(27,147)
(11,698)
(15,449)
Net cash (used in) provided by continuing operating activities
(740)
1,755
(2,495)
Net cash used in discontinued operating activities
(18)
(13)
(5)
Net cash (used in) provided by operating activities
(758)
1,742
(2,500)
Net cash used in investing activities
(23,148)
(19,056)
(4,092)
Net cash used in financing activities
(2,118)
(56)
(2,062)
Net change in cash, cash equivalents and restricted cash
$
(26,024)
$
(17,370)
$
(8,654)

The ~~$13.0~~$4.9 million increase in net cash provided by ~~our~~ operating activities before changes in operating assets and liabilities ~~for the three months ended March 31, 2022 compared to the same period of 2021,~~ was ~~mainly~~ due to ~~positive contributions from adding back~~lower cash settlements on derivative contracts partially offset by lower net income due to ~~cash the change in unrealized derivative losses.~~higher production costs and higher current income taxes The net ~~decrease~~increase in changes provided by operating assets and liabilities of ~~$15.4~~$37.8 million for the three months ended March 31, ~~2022~~2023 compared to the same period of ~~2021~~2022 was primarily related to ~~an increase~~positive changes in receivables accounts with joint venture owners and other assets ~~of $25.5 million which was partially offset by a $10.1 million increase~~along with positive changes in ~~liabilities.~~accounts payable and foreign income taxes (collectively $79.1 million). Partially offsetting these changes were negative changes in other receivables, crude oil inventory, deferred taxes and accrued liabilities and other (collectively ($41.3) million).

The ~~$4.1~~$4.6 million increase in net cash used in investing activities during the three months ended March 31, ~~2022~~2023 was due to increases in capital spending to costs associated with the development drilling programs in Egypt and Canada. For the three months ended March 31, 2022, cash used in investing activities was mainly for the Etame-8H development well and Etame field reconfiguration and other items to support the 2021/2022 drilling ~~Campaign. For the three months ended March 31, 2021, cash used in investing activities was mainly due to cash used in the purchase of Sasol’s interest in the Etame Block.~~campaign.

Net cash used in financing activities during the three months ended March 31, ~~2022~~2023 included ~~$1.9~~$6.7 million for dividend ~~distribution, $0.4~~distributions, $5.4 million for treasury stock repurchases made under our stock repurchase plan as discussed in Note 10 to our unaudited condensed consolidated financial statements or as a result of tax withholding on options exercised and on vested restricted stock as discussed in Note 1415 to our unaudited condensed consolidated financial statements, and $1.7 million of principal payments on our finance leases partially offset by ~~$0.2~~$0.3 million in proceeds from options exercised.

~~Capital Expenditures~~

For the three months ended March 31, 2022, cash used in financing activities was mainly due to dividend distributions of $1.9 million, cash used in the purchase of treasury shares as a result of tax withholding on options exercised of $0.4 million partially offset by proceeds received from options exercised of $0.2 million.

Capital Expenditures

For the three months ended March 31, 2023 we had accrual basis capital expenditures attributable to continuing operations of ~~$31.8~~$25.4 million compared to ~~$2.5~~$31.8 million accrual basis capital expenditures for the same period in ~~2021, excluding the Sasol acquisition.~~2022. For the three months ended March 31, ~~2022,~~2023, our ~~efforts were focused on~~cash spending related to the payments for the 2023 drilling campaigns in Egypt and Canada. During the same period in 2022, our spending was concentrated on the 2021/2022 drilling campaign, ~~and~~ Etame field reconfigurations and FSO projects. ~~During the same time in 2021, our spending was concentrated on the Sasol acquisition and obtaining certain long lead items for the 2021/2022 drilling campaign.~~

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

Table of Contents

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 Financial Statements for further discussion.

Commodity Price Hedging

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

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

See the table below for the unexpired contracts at March 31, 2023:

Settlement Period

Type of Contract

Index

Average Monthly Volumes

Weighted Average Put Price

Weighted Average Call Price

(Bbls)

(per Bbl)

April 2023 - June 2023

Collars

Dated Brent

95,500

65.00

100.00

Pursuant to the Facility entered into in May 2022, we are required to hedge a portion of our ~~hedging policy.~~anticipated oil production at the time we draw down on the Facility.

Subsequent Event

On ~~September 24, 2021,~~April 4, 2023, we entered into additional ~~commodity swaps at a Dated Brent weighted average price of $72.00 per barrel~~derivatives contracts for the ~~period from and including March 2022 to June 2022 for a quantity~~third quarter of ~~460,000 barrels. On January 6, 2022, we entered into additional commodity swaps at a Dated Brent weighted average price of $76.53 per barrel for~~2023. The details are in the period from and including July 2022 to September 2022 for a quantity of 375,000 barrels. On February 23, 2022, we entered into additional commodity swaps at a Dated Brent weighted average price of $85.01 per barrel for the period from and including April 2022 to June 2022 for a quantity of 234,000 barrels.chart below:

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

Settlement Period

Type of Contract

Index

Average Monthly Volumes

Weighted Average Put Price

Weighted Average Call Price

(Bbls)

(per Bbl)

July 2023 - September 2023

Collars

Dated Brent

95,000

65.00

96.00

Cash on Hand

At March 31, ~~2022,~~2023, we had unrestricted cash of ~~$18.9~~$52.1 million. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

Table of Contents

We currently sell all our crude oil production from Gabon under a ~~term contract that began in January 2020~~crude oil sales and ~~ends in July 2022. Pricing under this contract is~~marketing agreement ("COSMA") with Glencore. Under the COSMA all oil produced from the Etame G4-160 Block offshore Gabon from August 2022 through the Final Maturity Date of the Facility, will be bought and marketed by Glencore, with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

Revenues associated with the sales of our crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable. For reporting purposes, we record the EGPC’s share of production as royalties which are netted against revenue. With respect to taxes in Egypt, our income taxes under the terms of the Merged Concession Agreement are the liability of TransGlobe Petroleum International ("TGPI"), a wholly-owned indirect subsidiary of VAALCO. TGPI's income taxes are paid by EGPC on behalf of TGPI out of EGPC’s production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of TGPI are recognized as oil and gas sales revenue and income tax expense for reporting purposes.

For the three months ended March 31, 2023, all sales in Egypt were to Mercuria. Sales to Mercuria are normally settled within 30 days.

Revenues from the sale of crude oil, natural gas, condensate and NGLs in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. Prices are determined by reference to quoted market prices in active markets for crude oil, natural gas, condensate, and NGLs based on product, each adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are recognized net of royalties and transportation costs. Revenues are measured at the fair value of the consideration received.

Settlement of accounts receivable in Canada occur on the 25th of the following month after production.

Capital Resources, Liquidity and Cash Requirements

Historically, our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities in the Etame Marin block. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions. For example, we recently took actions to improve our liquidity position by entering into the Facility Agreement. We believe that the recent Facility significantly improves our financial flexibility and our ability to achieve accretive growth by providing access to cash if required for potential future development programs or to fund inorganic acquisition opportunities. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.

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

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

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

Merged Concession Agreement

On January 19, 2022, legacy subsidiaries of TransGlobe executed the Merged Concession Agreement with EGPC to update and merge TransGlobe’s three Egyptian concessions in West Bakr, West Gharib and NW Gharib (the “Merged Concession”). The modernization payments under the Merged Concession Agreement total $65.0 million and are payable over six years from the Merged Concession Effective Date. Under the Merged Concession Agreement, we will be required to pay an additional $10.0 million on February 1 for each of the next three years. In addition, we have committed to spending a minimum of $50.0 million over each five-year period for the 15 years of the primary term (totaling $150.0 million). Our ability to make scheduled payments arising from the Merged Concession Agreement will depend on our financial condition and operating performance, which is subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control.

Table of Contents

RBL Facility Agreement and Available Credit

On May 16, 2022, VAALCO Gabon (Etame), Inc. entered into Facility Agreement by and among VAALCO, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C. and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $50.0 million (the “Initial Total Commitment”). In addition, subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million. Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million.

The Facility provides for determination of the borrowing base asset based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is determined and re-determined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.

The Borrower’s obligations under the Facility Agreement are guaranteed by Guarantors and secured by interests, rights, activities, assets, entitlements, and development in the Etame Marin Permit (Block G64-160) Field and any other assets which are approved by the Majority Lenders (as defined in the Facility Agreement).

Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00% until the third anniversary of the Facility Agreement or (ii) 6.25% from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).

Pursuant to the Facility Agreement, we shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.

The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).

Cash Requirements

Our material cash requirements generally consist of finance leases, operating leases, purchase obligations, capital projects and 3D seismic processing, the ~~Sasol Acquisition~~TransGlobe acquisition transaction costs, dividend payments, funding of our share buyback program, merged concession agreement, future lease payments and abandonment funding, each of which is discussed in further detail below.

~~Sasol Acquisition~~

Abandonment Funding – ~~As a result~~Under the terms of ~~completing the Sasol Acquisition on February 25, 2021, our obligations with respect to development activities in~~ the Etame PSC, we have ~~increased based~~a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the ~~increase in our working interest in the~~ Etame ~~from 31.1 % at December 31, 2020, to 58.8%.~~Marin block. As a result of the ~~Sasol Acquisition,~~PSC Extension, annual funding payments are spread over the periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In November 2021, a new abandonment study was done and the estimate used for this purpose is approximately $81.3 million ($47.8 million, net ~~portion of production and costs relating~~to VAALCO) on an undiscounted basis. The new abandonment estimate has been presented to the ~~Company’s Etame operations increased from 31.1%~~Gabonese Directorate of Hydrocarbons as required by the PSC. At March 31, 2023, the balance of the abandonment fund was $10.7 million ($6.3 million, net to ~~58.8%. Reserves, production and financial results for the interests acquired~~VAALCO) on an undiscounted basis. The annual payments will be adjusted based on revisions in the ~~Sasol Acquisition have been included~~abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in ~~VAALCO’s results for periods after February 25, 2021.~~the “Abandonment funding” line item of the 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.

~~FSO Agreements~~

Table of Contents

Leases – We are ~~currently~~ a party to ~~an FPSO charter~~several operating and financing lease arrangements, including operating leases for the ~~production~~corporate office, a drilling rig, rental of marine vessels and helicopters, warehouse and storage ~~of all~~facilities, equipment and financing lease agreements for the FSO and generators used in the operations of the ~~crude oil~~Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. The annual costs of these leases are significant to us. For further information see Note 12 to our consolidated financial statements.

Merged Concession Agreement – On January 20, 2022, prior to the consummation of the Arrangement, TransGlobe announced a fully executed Merged Concession Agreement with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $15.0 million and signature bonus of $1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022. On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million. In accordance with the Merged Concession, we ~~produce. This contract~~agreed to substitute the February 1, 2023 payment and issue a $10.0 million credit against receivables owed from EGPC. We will ~~expire in September 2022.~~make three further annual equalization payments of $10.0 million each beginning February 1, 2024, until February 1, 2026. We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date"). As of March 31, 2023, the $50 million of financial work commitments had been delivered to EGPC.

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

~~The FSO Agreements require a prepayment of $2 million gross ($1.2 million net to VAALCO) in 2021 and $5 million gross ($3.2 million net) in~~

On October 19, 2022, of which $6 million will be recovered against future rentals. In addition, VAALCO Gabon agreed to pay a daily hire rate at certain rates specified therein, with such hire rate being based on the year within the term.

~~In connection with the implementation~~we issued final acceptance certificate of the FSO. On December 4, 2022, the first lifting from the FSO ~~we are required to incur certain capital expenses in order to facilitate~~was successfully completed at the ~~FSO. Current total capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO).~~same time the final remaining volumes from the FPSO were removed.

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

Drilling ~~Program~~Programs – In Egypt, we continued to use the EDC-64 rig in the Eastern Desert drilling campaign. We completed the Arta 77Hz horizontal well drilling at the beginning of 2023 and released the rig on January 11, 2023. The well is flowing at approximately 200 bopd with minimal water. We expect cleanup on this well to continue for an extended period of time. This delayed the 2023 drilling campaign. However, during the remainder of the quarter, we drilled and cased five development wells, (East Arta 53 ("EA-53"), K-81, K-79, Arta-80 Red Bed, and Arta 81 Red Bed).

Table of Contents

The K-79 well was drilled as a vertical development well with the ASL-D reservoir as the primary target, and the ASL-B and ASL-E reservoirs as secondary targets. The well spudded on February 21, 2023, and reached TD on March 1, 2023 at a depth of 1,739 meters in the ASL-F reservoir. Log analysis indicates the presence of 57.9m net pay, 9m in the ASL-D reservoir, 31 m in the ASL-B reservoir and 13.7m in the ASL-A sands. The well perforated in the ASL-B1 and B2 zones from 1,273 to 1,285m and 1,302 to 1,308m. Initial production commenced on March 15, 2023 at 192 bopd.

The Arta-80 development well reached its primary objective of the ~~2021/2022~~Red Bed reservoir approximately 24.4 meters higher than prognosis and encountered a total of 10 meters of net pay. The well spudded on March 10,2023 and reached TD on March 15,2023 at a depth of 1,250 meters in the Thebes Formation. Open hole log evaluation indicated the presence of 10.5 meters of net pay in the Red Bed primary reservoir. The top 9.5 meters of the Red Beds were perforated from 1,105 to 1,115 meters and began to produce on March 25, 2023 with initial production of 403 bopd.

In Canada, the 2023 drilling campaign commenced in ~~December 2021~~January 2023 with the drilling of 12-12-30-4W5 which was spud on January 28, 2023. The well was drilled to a total depth of 6,713 meters. The second well of the ~~Etame 8-H development~~ ~~well.~~ Inprogram, 16-30-29-3W5, was spud on February 22, 2023, and drilled to total depth of 4,403 meters. The 2 wells were completed in late March and early April and are currently being equipped for production.

TransGlobe Acquistion – On October 13, 2022, weVAALCO and AcquireCo completed the ~~drilling~~business combination with TransGlobe. At the effective time of the ~~Etame 8-H well~~Arrangement and ~~moved the drilling rig~~pursuant to the ~~Avouma platform~~Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to ~~drill~~ the ~~Avouma 3H-ST1 development well, which is targeting the Gamba reservoir.The initial flow rate~~effective time of the ~~ETAME 8-H well~~Arrangement was ~~5,000 BOPD, 2,560 BOPD net~~converted into the right to ~~VAALCO’s 58.8% working interest in 2022.~~ receive 0.6727 of a share of VAALCO common stock. The total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million. In ~~April 2022, the well was completed and brought online in April with an IP rate~~addition, we incurred $14.6 million of ~~approximately 3~~,~~100 gross BOPD,~~ ~~1,589 BOPD net to VAALCO’s 58.8% working interest in 2022~~.

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

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

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

Dividend Policy – On ~~November 3, 2021,~~February 14, 2023, we announced that our board of directors adopted of a quarterly cash dividend ~~policy~~ of an expected ~~$0.0325~~$0.0625 per common share per quarter, commencing in the first quarter of ~~2022. We paid~~ ~~on March 18, 2022~~ 2023 and also declared a quarterly cash dividend of ~~$1.9 million~~$0.0625 per common share, which was paid on March 31, 2023 to ~~the shareholders~~stockholders of record at the close of business on ~~February 18, 2022. Further we announced~~March 24, 2023. On May 9, 2023, our ~~intent~~board of directors declared a quarterly cash dividend of $0.0625 per common share to ~~pay a dividend~~ ~~of $0.0325 per~~ ~~share of common stock for the second quarter of 2022 ($0.13 annualized), which is~~ ~~payable~~be paid on June ~~24, 2022~~23, 2023 to stockholders of record at the close of business on May ~~25, 2022.~~

24, 2023.

Table of Contents

Share Buyback Program – On November 1, 2022, we announced that our board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with our business combination with TransGlobe. The board of directors also directed management to implement the 10b5-1 Plan to facilitate share purchases through open market purchases, privately-negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Exchange Act. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using our cash on hand and cash flow from operations. As of March 31, 2023, approximately $22.5 million remained available for repurchase under current authorizations.

Trends and Uncertainties

~~COVID-19 Pandemic~~

Geopolitical Climate and Other Market Forces – ~~While crude~~Increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain, which in turn have had, and may continue to have, an impact on our business. Management believes the ongoing war between Russia and Ukraine and its related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy. For example, we noticed that the lead times associated with obtaining materials to support our operations and drilling activities has lengthened, leading to delays and, in most cases, prices for materials have increased.

The outbreak of armed conflict between Russia and Ukraine in February 2022 and the subsequent sanctions imposed on the Russian Federation has, and may continue to have, a destabilizing effect on the European continent and the global oil ~~prices are currently at the highest levels seen~~and natural gas markets. The ongoing conflict has caused, and could intensify, volatility in ~~recent years, the continued spread of COVID-19, including vaccine-resistant strains, or deterioration in crude~~ oil and natural gas prices, and the extent and duration of the military action, sanctions and resulting market disruptions could ~~result~~be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.

Further, the slowdown in ~~additional~~the Chinese economy is negatively impacting the global market and the global supply chain problems may have a material adverse ~~impacts~~impact on our financial results ofand business operations, ~~cash flows~~including our timing and ~~financial position, including asset impairments. The health~~ability to complete future drilling campaigns and other efforts required to advance the development of our ~~employees, contractors~~crude oil, natural gas 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.NGLs properties.

Commodity Prices – Historically, the markets for oil, ~~and~~ natural gas and NGLs have been volatile. Oil, natural gas and ~~NGL~~NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC+. On October 5, 2022, OPEC+ announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022. In ~~July 2021,~~April 2023, OPEC+ ~~agreed~~reaffirmed its decision to ~~increase~~reduce overall oil production ~~beginning~~by 2 MMBbls per day from November 2022 through December 2023. Additionally, certain member countries announced additional voluntary reductions totaling 1.2 MMBbls through December 2023, which is in ~~August 2021~~addition to ~~phase out~~the 500 MBbls per day voluntary reduction announced by Russia in February 2023. Included in the 1.2 MMBbls per day reduction was a ~~portion~~voluntary reduction by the Gabonese government of 8 MBbls per day, which will go into effect in May 2023 and is expected to extend through the remainder of 2023. To date, we have not received any mandate to reduce our current oil production from the Etame Marin block as a result of the ~~prior production cuts.~~OPEC+ initiative. Brent crude prices were approximately ~~$107~~$79.19 per barrel as of March 31, ~~2022. The decision to increase production was reaffirmed by an OPEC+ meeting held on March 31, 2022.~~2023.

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

~~Hedging~~

Table of Contents

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

Hedging

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

See the table below for the unexpired ~~barrels as of~~contracts entered into prior to March 31, ~~2022:~~2023:

Settlement Period

Type of Contract

Index

Average Monthly Volumes

Weighted Average Put Price

Weighted Average Call Price

(Bbls)

(per Bbl)

April 2023 - June 2023

Collars

Dated Brent

95,500

65.00

100.00

Pursuant to the Facility entered into in May 2022, we are required to hedge a portion of our anticipated oil production at the time that we draw down on the Facility.

Subsequent Event

On April 3, 2023, we entered into additional derivatives contracts for the third quarter of 2023. The details are in the chart below:

Settlement Period

Type of Contract

Index

Average Monthly Volumes

Weighted Average Put Price

Weighted Average Call Price

(Bbls)

(per Bbl)

July 2023 - September 2023

Collars

Dated Brent

95,000

65.00

96.00

CRITICAL ACCOUNTING POLICIES

There have been no material changes to our critical accounting policies subsequent to December 31, ~~2021.~~2022.

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

Three Months Ended March 31, ~~2022~~2023 Compared to the Three Months Ended March 31, ~~2021~~2022

Net income for the three months ended March 31, ~~2022~~2023 was ~~$12.2~~$3.5 million compared to net income of ~~$9.9~~$12.2 million for the same period of ~~2021.~~2022. See discussion below for changes in revenue and expense.

Crude oil and natural gas revenuesincreased ~~$28.9~~$11.7 million, or approximately ~~72.6%~~17%, to $80.4 million during the three months ended March 31, ~~2022 compared to~~2023 from $68.7 million for the same period ~~of 2021.~~in the prior year. The revenue increase ~~in revenue~~ is attributable to higher volumes sold in Gabon and the addition of the Egypt and Canada segments acquired in the Arrangement with TransGlobe, partially offset by lower realized sales ~~prices and Sasol’s additional working interest for the full three months ended March 31, 2022.~~prices.

Three Months Ended March 31,
2022
2021
Increase/(Decrease)
(in thousands except per bbl information)
Net crude oil sales volume (MBbls)
616
619
(3)
Average crude oil sales price (per Bbl)
$
109.65
$
61.31
$
48.34
Net crude oil revenue
$
68,656
$
39,774
$
28,882
Operating costs and expenses:
Production expense
18,360
16,133
2,227
Exploration expense
127
142
(15)
Depreciation, depletion and amortization
4,673
4,148
525
General and administrative expense
4,994
4,547
447
Bad debt expense
492
101
391
Total operating costs and expenses
28,646
25,071
3,575
Other operating expense, net
(5)
(360)
355
Operating income
$
40,005
$
14,343
$
25,662

The revenue changes in the three months ended March 31, ~~2022~~2023 compared to the same period in ~~2021~~2022 identified as related to changes in price or volume, are shown in the table below:

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

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

*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil, natural gas and NGL revenues increased $11.7 million, or approximately 17.0%, during the three months ended March 31, 2023 compared to the same period of 2022.

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each ~~quarter from the FPSO,~~year and thus crude oil sales do not always coincide with volumes produced in any given ~~quarter. We made~~ ~~two~~ ~~liftings~~year. The Company’s Gabon segment contributed $36.7 million of revenue to the Company’s total revenue during the three months ended March 31, ~~2022 and three liftings~~2023. This compares to the $68.7 million of revenue contributed by the Segment during ~~the three months March 31, 2021. Although the number of barrels sold at March 31, 2022 is about the same as the numbers of barrels sold during March 31, 2021,~~ the three months ended March 31 ~~2022 includes Sasol’s interest for the entire period while during the same period~~,2022. The total barrels lifted in 2021, Sasol’s interest was included after the acquisition date, February 25, 2021. Due to field start-up operational issues which pushed out the timing of third lifting until April 4, 2022, only two liftings occurredGabon for the three months ended March 31 was less than the barrels lifted during the same period in 2022, mainly due to the timing of liftings. In addition, the Gabon per barrel price received during the three months ended March 31, 2023 was $30.00 less than the price received in 2022. Our share of crude oil inventory, ~~aboard the FPSO,~~ excluding royalty barrels, was approximately ~~174,250 barrels~~408,543 and ~~53,858~~174,250 barrels at March 31, 2023 and 2022, ~~and 2021,~~ respectively.

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC. During the three months ended March 31, 2023, all the oil sold in Egypt was through third party cargo sales. The Company’s Egypt segment contributed $34.8 million of revenue to the Company’s total revenue for the quarter. At the end of the quarter, the Company’s Egypt segment had approximately 63,000 barrels at March 31, 2023 in oil inventory. Since the Company acquired its Egyptian segment in the fourth quarter of 2022, there are no comparable revenues for the three months ended March 31 ,2022.

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $8.9 million of revenue to the Company’s total revenue for the quarter. Since the Company acquired its Canadian segment in the fourth quarter of 2022, there are no comparable revenues for the three months ended March 31 ,2022

Production expenses increased ~~$2.2~~$9.8 million, or approximately ~~13.8%~~54%, for the three months ended March 31, ~~2022 compared~~2023 to $28.2 million from $18.4 million for the same period in ~~2021.~~the prior year. The increase in production expense was primarily ~~related to~~driven by increased production and costs associated with the TransGlobe combination as well as higher ~~FPSO~~ costs ~~boat expense,~~associated with boats, diesel and operating costs. VAALCO has seen inflationary pressure on personnel ~~costs,~~ and ~~domestic market obligation (“DMO”)~~contractor costs. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended March 31, ~~2022 increased~~2023 decreased to ~~$29.81~~$23.91 per barrel from ~~$26.02~~$29.83 per barrel for the three months ended March 31, ~~2021~~2022 primarily as a result of ~~lower~~

higher sales ~~volumes due to production interruptions in order to facilitate~~volumes. For both the ~~2021/~~three months ended March 31, 2023 and 2022, ~~drilling campaign. While~~respectively, we have not experienced any material operational disruptions associated with the current worldwide COVID-19 ~~pandemic,~~pandemic. For the three months ended March 31, 2023 the costs associated with proactive measures related to COVID were not material. For the three months ended March 31, 2022 , we ~~have~~ incurred ~~approximately~~ $0.9 ~~million and $0.6~~ million in higher costs related to the proactive measures taken in response to the ~~pandemic~~ pandemic.

Exploration expense for the three months ended March 31, 2023 and for the three months ended March 31, 2022 was not material to our results.

Depreciation, depletion and amortization costs increased $19.7 million, or approximately 423% for the three months ended March 31, 2023 to $24.4 million from $4.7 million for the same period in the prior year. The increase in depreciation, depletion and amortization expense for the three months ended March 31, 2023 compared to thee months ended march 31 2022, is due to higher depletable costs associated with the FSO, the field reconfiguration capital costs at Etame and the step-up to fair value of the TransGlobe assets.

General and administrative expenses increased $0.2 million, or 5% for the three months ended March 31, 2023 to $5.2 million from$5.0 million for the same period in the prior year. The increase in general and administrative expenses is primarily due to higher professional fees for the three months ended March 31, 2023 compared to the same period in 2022.

Credit losses and other increased by $0.4 to $0.9 million for the three months ended March 31, 2023 from $0.5 million for the three months ended March 31, 2022. We adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”) on January 1, 2023. In connection with the adoption of ASU 2016-13, we established an opening balance sheet adjustment related to a receivable from a state sponsored oil refinery where we delivered oil pursuant to the domestic market needs obligation under the Etame PSC. During the three months ended March 31, 2023, we recognized an additional amount to the credit loss allowance of $0.4 million for crude oil delivered to the refinery during the quarter. For the three months ended March 31, 2022, no allowance was established related to this receivable as the state sponsored oil refinery made timely payments of the amounts owed to the Company.

Table of Contents

Historically, we reported amounts currently considered as credit loss expense and other as bad debt expense and, prior to the adoption of ASU 2016-13, bad debt expense mainly related to the our VAT balances under the Etame PSC. When we are invoiced by a vendor an amount is added for VAT (a cost plus VAT amount) and we pay the vendor invoice. Since we are an oil and gas company, we are exempt from VAT and therefore request reimbursement from the State of Gabon for VAT for amounts we’ve paid. Due to the late reimbursement nature of the VAT receivable by the State of Gabon, the Company established an allowance against the receivable The allowance related to the VAT receivable was $8.4 million on December 31, 2022. For the three months ended March 31, 2023 we added $0.5 million to the allowance account for the current’s quarters activity. We are now reporting under the condensed consolidated income statement line item “Credit losses and other” the activity related to financial assets under ASC 2016-13 and activity regarding other allowance accounts. For more information on credit losses and other allowances, see Note 1 to the unaudited condensed consolidated financial statements.

Other operating expense, net for each of the three months ended March 31, 2023 and 2022 was not material to our results.

Derivative instruments gain (loss), net is attributable to our swaps and ~~2021, respectively.~~

~~Depreciation, depletion and amortization~~ ~~costs increased $0.5~~collars as discussed in Note 8 to the unaudited condensed consolidated financial statements. Derivative loss decreased by $31.8 million, or approximately ~~12.7% due~~100% to ~~the higher depletable base as a result of capital expenditures related to the 2021/2022 drilling program.~~

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

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

~~Other operating income (expense), net~~an immaterial loss for the three months ended March 31, ~~2022 and~~2023 from a loss of $31.8 million during the same period in the prior year. Derivative gains (losses) for the three months ended March 31, ~~2021 was not material to our results.~~

~~Derivative instruments loss, net~~ ~~is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements.~~ ~~The $31.8 million and $6.0 million losses for the three months ended March 31,~~ 2022 ~~and 2021~~ are a result of the increase in the price of Dated Brent crude oil ~~during the two periods. Every quarter in 2021 and continuing in 2022 Dated brent crude oil process have increased. Since the Company owes the counterparty for any Dated Brent price~~ over the initial strike price per barrel ~~value and~~of the ~~Company continued~~option over the three months ended March 31, 2022. During 2022, we changed the type of our derivative instruments from swaps to ~~place on additional hedges in 2021 and 2022, the loss associated with the derivates have increased.~~costless collars. Our derivative instruments currently cover a portion of our production through September 2023.

Interest expense, net was $2.2 million for the three months ended March 31, 2023 compared to an expense of $0.0 million during the same period in 2022. The increase of net interest expense for the three months ended March 31, 2023, primarily results from our finance lease relating to the FSO but also includes commitments fees incurred on the Facility, amortization of debt issue costs related to the Facility and interest associated with our other finance leases partially offset by interest income.

Other (expense) income changed by $0.4 million to expense of $1.1 million for the three months ended March 31, 2023 from an expense of $0.7 million for the three months ended March 31, 2022. Other (expense) income, net normally consists of foreign currency gains and (losses) as discussed in Note 1 to the unaudited condensed consolidated financial statements. However, the three months ended March 31, 2023, also included $1.4 million expense from a transition period adjustment of the bargain purchase gain related to the Arrangement with TransGlobe as discussed in Note 3 to our unaudited condensed consolidated financial statements. Foreign currency losses are the primary driver for the activity during the three months ended March 31, 2022.

~~Other, net~~

Income tax expense (benefit) for the three months ended March 31, 2023 was an expense of $14.8 million. This is comprised of current tax expense of $12.3 million and $2.5 million of deferred tax expense. Income tax expense (benefit) for the three months ended March 31, 2022 increased $5.4 million from an expense of $0.7 million for the three months ended March 31, 2022 compared to $4.6 million of income in the same period of 2021. For the three months ended March 31, 2022 Other, net primarily consists of foreign currency losses as discussed in Note 1 to the condensed consolidated financial statements. For the three months ended March 31, 2022, the $4.6 million of income in Other, net is primarily attributable to $7.7 million for the bargain purchase gain and expenses of $2.2 million for the difference in book to tax basis caused by the bargain purchase gain and $1.0 million for an acquisition success fee.

~~Income tax expense (benefit)~~ ~~for the three months ended~~ ~~March 31, 2022~~was a benefit of $4.6 million. This iswas comprised of ~~$12.5~~$10.3 million of net deferred tax benefit and a current tax expense of ~~$ (5.7) million. See Note 15 to the condensed consolidated financial statements.~~$5.7 million.

Table of Contents

~~ITE~~M ITEM3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~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~~

FOREIGN EXCHANGE RISK

Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of March 31, ~~2022,~~2023, we had net monetary assets of ~~$11.1~~$22.6 million (XAF ~~6,525.3~~13,642.2 million) denominated in XAF. A 10% weakening of the CFA relative to the U.S. dollar would have a ~~$1.0~~$2.1 million reduction in the value of these net assets. For the three months ended March 31, ~~2022,~~2023, we had expenditures of approximately ~~$7.3~~$11.3 million (net to VAALCO), denominated in XAF.

Related to our Canadian operations, our currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars. We estimate that a 10% decrease in the value of the Canadian dollar against the US dollar would increase the value of the net assets for the three months ended March 31, 2023 by approximately $0.8 million. Conversely, a 10% increase in the value of the Canadian dollar against the US dollar would decrease the value of the net assets for the three months ended March 31, 2023 by approximately $0.9 million.

We are also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while we are generally able to use the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates at March 31, 2023, we estimate that a 10% increase in the value of the Egyptian pound against the US dollar would increase the cash value for the three months ended March 31, 2023 by less than $0.1 million. Conversely, a 10% decrease in the value of the Egyptian pound against the US dollar would decrease our US dollar cash value for the three months ended March 31, 2023 by less than $0.1 million.

COUNTERPARTY ~~Risk~~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~~

COMMODITY PRICE RISK

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

unpredictable in recent years, and this volatility may continue. Sustained low crude oil and natural gas prices or a resumption of the decreases in crude oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms.

With respect to our crude oil sales in Gabon, the price received is based on Dated Brent prices plus or minus a differential. If crude oil sales were to remain constant at the most recent quarterly sales volumes of ~~616~~459 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a ~~$3.1~~$2.3 million decrease per quarter in revenues and operating income (loss) and a ~~$2.8~~$2.1 million decrease per quarter in net income (loss).

Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company. The PSCs provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between VAALCO’s recognition of costs and their recovery as VAALCO accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSCs, our share of excess ranges between 5% and 15%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost oil ranges from 25% to 40% in Egypt. The balance of the production after maximum cost recovery is shared with the government (profit oil). Depending on the contract, the Egyptian government receives 67% to 84% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less cost oil and may receive more profit-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil.

With respect to our crude oil and NGL sales in Canada, the prices received is based on NYMEX WTI (west Texas Intermediate) prices plus or minus a differential. Natural gas sales are based on Canadian index price that whose price is based, in part. on the NYMEX Henry Hub Natural Gas futures contracts. If Canadian BOE sales were to remain constant at the most recent quarterly sales volumes of 211 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $1.1 million decrease per quarter in revenues and operating income (loss) and a $0.8 million decrease per quarter in net income (loss).

Table of Contents

As of March 31, ~~2022,~~2023, we had unexpired derivative instruments outstanding covering ~~954~~approximately 287 MBbls of production through June 2023. In April of 2023, we added derivative contracts covering 285 MBbls of production from July 2023 through September ~~2022.~~2023. These instruments were intended to be an economic hedge against declines in crude oil prices; however, they were not designated as hedges for accounting purposes. See Note 8 to our unaudited condensed consolidated financial statements for further discussion.

Interest Rate RISK

Changes in market interest rates affect the amount of interest owed on outstanding balances under our Facility. However as of March 31, 2023 we had no amounts drawn under the facility. The commitment fees on the undrawn availability under the Facility are not subject to changes in interest rates. Additionally, changes in market interest rates could impact interest costs associated with any future debt issuances.

ITEM4. CO~~NTROLS~~CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on their evaluation as of March 31, ~~2022,~~2023, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance ~~level.~~level due to the material weaknesses in control over financial reporting previously disclosed in Part II, Item 9A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

~~Changes~~

Notwithstanding the identified material weaknesses, management, including our principal executive officer and principal financial officer, believes the consolidated financial statements included in this Quarterly Report on Form 10-Q fairly represent in all material respects our financial condition, results of operations and cash flows at and for the periods presented in accordance with GAAP.

On October 13, 2022, we completed the acquisition of TransGlobe, see Note 3 to the unaudited condensed consolidated financial statements, which operated under its own set of internal controls. During the three months ended March 31, 2023, we transitioned certain TransGlobe processes to our internal control processes and added other internal controls over significant processes specific to the acquisition and to post-acquisition activities, including internal controls associated with the valuation of certain assets acquired and liabilities assumed in the acquisition. We will continue the process of integrating internal control over financial reporting for TransGlobe and plans to incorporate TransGlobe in the evaluation of our disclosure controls and procedures beginning in the second quarter of 2023.

~~There~~

MANAGEMENT’S PLAN FOR REMEDIATION OF THE MATERIAL WEAKNESS

As previously described in Part II, Item 9A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, we began implementing a remediation plan to address the material weaknesses mentioned above. The weaknesses will not be considered remediated until the applicable controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. We expect that the remediation of the material weaknesses will be completed prior to the end of fiscal year 2023.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Except for the activities taken related to the remediation of the material weaknesses described above, there have been no changes in our internal control over financial reporting during the three months ended March 31, ~~2022~~2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II. OTHER INFORMATION

ITEM1.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.

ITEM1A.RISK FACTORS

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

For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our ~~2021~~2022 Form 10-K. There have been no material changes in our risk factors from those described in our ~~2021~~2022 Form 10-K.

There were no sales of unregistered securities during the quarter ended March 31, 2023 that were not previously reported on a Current Report on Form 8-K.

On November 3, 2021, we announced that our board of directors adopted a cash dividend policy.

On February 14, 2023, our board of directors declared a quarterly cash dividend of $0.0625 per common share, which was paid on March 31, 2023 to stockholders of record at the close of business on March 24, 2023. On May 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on June 23, 2023 to stockholders of record at the close of business on May 24, 2023.

On November 1, 2022, we announced that our board of directors formally ratified and approved the share buyback program ("the Plan") that was announced on August 8, 2022 in conjunction with our business combination with TransGlobe. The board of directors also directed management to implement the Plan to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Exchange Act. The Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using our cash on hand and cash flow from operations.

The following table represents details of the various repurchases under the Plan during the quarter ended March 31, 2023:

See Note 14 to the unaudited condensed consolidated financial statements for further discussion. Subsequent to March 31, 2023 and through May 9, 2023, the following table represents the details of various repurchases under the Plan:

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



PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets March 31, 2023 and December 31, 2022	2
~~March 31, 2022 and December 31, 202~~1	2
Condensed Consolidated Statements of Operations
and Comprehensive Income Three Months Ended March 31, ~~2022~~2023 and ~~202~~20221	3
Condensed Consolidated Statements of Shareholders’ Equity
Three Months Ended March 31, ~~2022~~2023 and ~~2021~~2022	4
Condensed Consolidated Statements of Cash Flows
Three Months Ended March 31, ~~2022~~2023 and ~~202~~20221	5
Notes to Condensed Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29 45
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37 62
ITEM 4. CONTROLS AND PROCEDURES	38 63
PART II. OTHER INFORMATION	38 64
ITEM 1. LEGAL PROCEEDINGS	38 64
ITEM 1A. RISK FACTORS	38 64
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	64
ITEM 6. EXHIBITS	3966

	*Three Months Ended March 31,*
	*2023*		*2022*
	*(in thousands)*
Supplemental disclosure of cash flow information:
Interest paid, net of amounts capitalized	$	1,488	$	—
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	39,584	$	26,113
Recognition of right-of-use finance lease assets and liabilities	$	1,429	$	1,851

*(in thousands)*	*Gabon*		*Egypt*		*Canada*		*Equatorial Guinea*		*Corporate and Other*		*Total*
Total assets from continuing operations:
As of March 31, 2023	$	381,009	$	270,629	$	116,554	$	11,013	$	44,778	$	823,983
As of December 31, 2022 (1)		395,393	$	293,640	$	110,071	$	10,861	$	45,676	$	855,641

	*Common Shares Issued*		*Treasury Shares*			*Common Stock*		*Additional Paid-In Capital*		*Accumulated Other Comprehensive Loss*			*Treasury Stock*			*Retained Earnings*			*Total*
	*(in thousands)*
Balance at January 1, 2023		119,483		(11,630	)	$	11,948	$	353,606	$	1,179		$	(47,652	)	$	147,024		$	466,105
Shares issued - stock-based compensation		633		(187	)		64		210		—			—			—			274
Stock-based compensation expense		—		—			—		683		—			—			—			683
Common Shares Purchased		—		(981	)		—		—		—			(4,517	)		—			(4,517	)
Treasury stock		—		—			—		—		—			(860	)		—			(860	)
Dividend Distributions		—		—			—		—		—			—			(6,735	)		(6,735	)
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023		—		—			—		—		—			—			(3,120	)		(3,120	)
Other comprehensive loss		—		—			—		—		(125	)		—			—			(125	)
Net income		—		—			—		—		—			—			3,470			3,470
Balance at March 31, 2023		120,116		(12,798	)	$	12,012	$	354,499	$	1,054		$	(53,029	)	$	140,639		$	455,175


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

	*As of March 31,*
	*2023*		*2022*
	*(in thousands)*
Cash and cash equivalents	$	52,119	$	18,939
Restricted cash - current		76		4,230
Restricted cash - non-current		1,771		1,752
Abandonment funding		6,268		21,369
Total cash, cash equivalents and restricted cash	$	60,234	$	46,290


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


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

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

	*Three Months Ended March 31, 2023*
(in thousands)	*Gabon*			*Egypt*			*Canada*			*Equatorial Guinea*			*Corporate and Other*			*Total*
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	36,737		$	34,784		$	8,882		$	—		$	—		$	80,403
Operating costs and expenses:
Production expense		14,415			11,110			2,254			362			59			28,200
Exploration expense		8			—			—			—			—			8
Depreciation, depletion and amortization		9,845			10,795			3,711			—			66			24,417
General and administrative expense		618			179			—			129			4,298			5,224
Credit losses and other		935			—			—			—			—			935
Total operating costs and expenses		25,821			22,084			5,965			491			4,423			58,784
Operating income (loss)		10,916			12,700			2,917			(491	)		(4,423	)		21,619
Other income (expense):
Derivative instruments gain, net		—			—			—			—			21			21
Interest (expense) income, net		(1,507	)		(808	)		(4	)		—			73			(2,246	)
Other income (expense), net		517			—			—			(1	)		(1,656	)		(1,140	)
Total other expense, net		(990	)		(808	)		(4	)		(1	)		(1,562	)		(3,365	)
Income (loss) from continuing operations before income taxes		9,926			11,892			2,913			(492	)		(5,985	)		18,254
Income tax expense		6,578			4,992			—			—			3,201			14,771
Income (loss) from continuing operations		3,348			6,900			2,913			(492	)		(9,186	)		3,483
Loss from discontinued operations, net of tax		—			—			—			—			(13	)		(13	)
Net income (loss)	$	3,348		$	6,900		$	2,913		$	(492	)	$	(9,199	)	$	3,470
Consolidated capital expenditures	$	3,689		$	11,571		$	10,165		$	—		$	—		$	25,425

	*Three Months Ended March 31, 2022*
*(in thousands)*	*Gabon*			*Equatorial Guinea*			*Corporate and Other*			*Total*
Revenues:
Crude oil and natural gas sales	$	68,656		$	—		$	—		$	68,656
Operating costs and expenses:
Production expense		18,081			219			60			18,360
Exploration expense		127			—			—			127
Depreciation, depletion and amortization		4,653			—			20			4,673
General and administrative expense		593			99			4,302			4,994
Credit losses and other		492			—			—			492
Total operating costs and expenses		23,946			318			4,382			28,646
Other operating expense, net		(5	)		—			—			(5	)
Operating income		44,705			(318	)		(4,382	)		40,005
Other income (expense):
Derivative instruments loss, net		—			—			(31,758	)		(31,758	)
Interest (expense) income, net		(6	)		—			3			(3	)
Other expense, net		(638	)		(1	)		(57	)		(696	)
Total other expense, net		(644	)		(1	)		(31,812	)		(32,457	)
Income from continuing operations before income taxes		44,061			(319	)		(36,194	)		7,548
Income tax (benefit) expense		7,858			—			(12,486	)		(4,628	)
Income (loss) from continuing operations		36,203			(319	)		(23,708	)		12,176
Loss from discontinued operations, net of tax		—			—			(12	)		(12	)
Net income (loss)	$	36,203		$	(319	)	$	(23,720	)	$	12,164
Consolidated capital expenditures	$	31,780		$	—		$	—		$	31,780


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



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

Block	*Merged Concession*			*South Ghazalat*
Year acquired ⁽¹⁾		2020			2013
Expiry date		2035			2039
Extensions
Exploration		N/A			N/A
Development		+ 5 years			20 + 5 years
Production Tranche (MBopd)		0-25			0-5
Maximum cost oil		40	%		25	%
Excess cost oil - Contractor		15	%		5	%
Depreciation per quarter
Operating		100	%		100	%
Capital		6	%		5	%
Production Sharing Oil:
Contractor		30	%*		17	%
Government		70	%*		83	%

*Merged Concession profit oil is set on a scale according to average Brent price and production:
	*Crude oil produced (MBopd)*
Brent Price ($/bbl)	*Less than or equal to 5 MBopd*		*More than 5 MBopd and less than or equal to 10 MBopd*		*More than 10 MBopd and less than or equal to 15 MBopd*		*More than 15 MBopd and less than or equal to 25 MBopd*		*More than 25 MBopd*
	*Government %*	*Contractor %*	*Government %*	*Contractor %*	*Government %*	*Contractor %*	*Government %*	*Contractor %*	*Government %*	*Contractor %*
Less than or equal to $40/bbl	67	33	68	32	69	31	70	30	71	29
More than $40/bbl and less than or equal to $60/bbl	68	32	69	31	70	30	71	29	72	28
More than $60/bbl and less than or equal to $80/bbl	70	30	71	29	72	28	74	26	76	24
More than $80/bbl and less than or equal to $100/bbl	72.5	27.5	73	27	74	26	76	24	78	22
More than $100/bbl	75	25	76	24	77	23	78	22	80	20


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


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


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


	Number of Shares Underlying SARs	Weighted Average Exercise Price Per Share		Term	Aggregate Intrinsic Value
	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2022	362	$	1.81
Granted	0		—
Exercised	(59)		1.41
Unvested SARs forfeited	—		—
Vested SARs expired	—		—
Outstanding at March 31, 2022	303	$	1.89	1.75	$	1,402
Exercisable at March 31, 2022	237	$	1.94	1.65	$	1,086

*(in thousands)*
Price	$	(53,832	)
Volume		66,690
Other		(1,111	)
	$	11,747

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Programs		Maximum Amount that May Yet Be Used to Purchase Shares Under the Program
January 1, 2023 - January 31, 2023		350,832	$	4.27		350,832	$	25,502,669
February 1, 2023 - February 28, 2023		326,992	$	4.59		326,992	$	24,003,172
March 1, 2023 - March 31, 2023		303,176	$	4.95		303,176	$	22,503,206
Total		981,000				981,000


3.1	Restated 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~~3.1.1	~~Third Amended and~~Certificate of Amendment to Restated ~~Bylaws~~Certificate of Incorporation of VAALCO, dated October 13, 2022 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 13, 2022 and incorporated herein by reference).
3.2	Third Amended and Restated Bylaws, dated July 30, 2020 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 4, 2020 and incorporated herein by reference).
3.3	Certificate of Elimination of Series A Junior Participating Preferred Stock of VAALCO Energy, Inc., dated as of December 22, 2015 (filed as Exhibit 3.2 to the ~~Company’s~~Company’s Current Report on Form 8-K filed on December 23, 2015, and incorporated herein by reference).
10.1*	~~Amendment No. 1 to Employment~~Separation Agreement, ~~effective as of January 27, 2022,~~ by and between VAALCO Energy, Inc. and ~~George Maxwell~~David DesAutels, dated as of March 8, 2023 (filed as Exhibit ~~10.1~~10.32 to the Company’s ~~Current~~Annual Report on Form ~~8-K~~10-K filed on ~~January 28, 2022~~April 6, 2023 and incorporated herein by reference).
10.2*	~~Amendment No. 1 to Employment~~Consulting Agreement ~~effective as of January 27, 2022, by and~~ between VAALCO Energy ~~Inc.~~ and ~~Ronald Bain~~David DesAutels, dated as of March 8, 2023, (filed as Exhibit ~~10.2~~10.33 to the Company’s ~~Current~~Annual Report on Form ~~8-K~~10-K filed on ~~January 28, 2022~~April 6, 2023 and incorporated herein by reference).
~~10.3~~31.1(a)(a)**	~~Agreement for the Provision of Subsea Construction and Installation Services, by and between VAALCO Gabon, SA and DOF Subsea Canada Corp., dated March 17, 2022.~~
~~31.1(a)~~	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
~~31.2~~31.2(a)~~(a)~~	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
~~32.1~~32.1(b)~~(b)~~	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
~~32.2~~32.2(b)~~(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.DEF(a)~~101.LAB(a)	Inline XBRL ~~Definition~~Label Linkbase Document.
~~101.LAB(a)~~101.PRE(a)	Inline XBRL ~~Label~~Presentation Linkbase Document.
~~101.PRE(a)~~104	Cover Page Interactive Data File (Formatted as Inline XBRL ~~Presentation Linkbase Document.~~and contained in Exhibit 101).


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

(in thousands)