10-Q

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

For the quarterly period ended June 30, 2023

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 1-32167

VAALCO Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware	76-0274813
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
9800 Richmond Avenue Suite 700 Houston, Texas	77042
(Address of principal executive offices)	(Zip code)

(713) 623-0801

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the 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  ☒    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  ☒    No  ☐

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

Large accelerated filer	☐	Accelerated filer	☒
Non‑accelerated filer	☐	Smaller reporting company Emerging growth company	☐ ☐

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

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

As of August 4, 2023, there were outstanding 106,475,814 shares of common stock, $0.10 par value per share, of the registrant. 

VAALCO ENERGY, INC. AND SUBSIDIARIES

Table of Contents

PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets June 30, 2023 and December 31, 2022	2
Condensed Consolidated Statements of Operations and Comprehensive Income Three and Six Months Ended June 30, 2023 and 2022	3
Condensed Consolidated Statements of Shareholders’ Equity Three and Six Months Ended June 30, 2023 and 2022	4
Condensed Consolidated Statements of Cash Flows Six Months Ended June 30, 2023 and 2022	5
Notes to Condensed Consolidated Financial Statements (unaudited)	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	45
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	65
ITEM 4. CONTROLS AND PROCEDURES	66
PART II. OTHER INFORMATION	67
ITEM 1. LEGAL PROCEEDINGS	67
ITEM 1A. RISK FACTORS	67
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	67
ITEM 5. OTHER INFORMATION	68
ITEM 6. EXHIBITS	69

1

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

	As of June 30, 2023			As of December 31, 2022
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	46,186		$	37,205
Restricted cash		113			222
Receivables:
Trade, net		57,360			52,147
Accounts with joint venture owners, net of allowance for credit losses of $0.5 and $0.3 million, respectively		216			15,830
Foreign income taxes receivable		—			2,769
Other, net of allowance for credit losses of $3.5 and $0.0 million, respectively		66,615			68,519
Crude oil inventory		10,800			3,335
Prepayments and other		18,077			20,070
Total current assets		199,367			200,097
Crude oil and natural gas properties, equipment and other - successful efforts method, net		481,740			495,272
Other noncurrent assets:
Restricted cash		1,779			1,763
Value added tax and other receivables, net of allowance of $9.5 million and $8.4 million, respectively		8,807			7,150
Right of use operating lease assets		1,639			2,777
Right of use finance lease assets		90,584			90,698
Deferred tax assets		37,155			35,432
Abandonment funding		6,268			20,586
Other long-term assets		1,674			1,866
Total assets	$	829,013		$	855,641
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	40,716		$	59,886
Accounts with joint venture owners		6,284			—
Accrued liabilities and other		84,104			91,392
Operating lease liabilities - current portion		1,667			2,314
Finance lease liabilities - current portion		7,684			7,811
Foreign income taxes payable		12,575			—
Current liabilities - discontinued operations		673			687
Total current liabilities		153,703			162,090
Asset retirement obligations		42,958			41,695
Operating lease liabilities - net of current portion		130			686
Finance lease liabilities - net of current portion		79,856			78,248
Deferred tax liabilities		82,895			81,223
Other long-term liabilities		17,465			25,594
Total liabilities		377,007			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; 160,000,000 shares authorized, 121,205,919 and 119,482,680 shares issued, 106,997,933 and 107,852,857 shares outstanding, respectively		12,121			11,948
Additional paid-in capital		355,206			353,606
Accumulated other comprehensive income		3,060			1,179
Less treasury stock, 14,207,986 and 11,629,823 shares, respectively, at cost		(59,055	)		(47,652	)
Retained earnings		140,674			147,024
Total shareholders' equity		452,006			466,105
Total liabilities and shareholders' equity	$	829,013		$	855,641

See notes to condensed consolidated financial statements.

2

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands, except per share amounts)
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	109,240		$	110,985		$	189,643		$	179,641
Operating costs and expenses:
Production expense		38,604			25,475			66,804			43,835
FPSO Demobilization - Norms Waste Disposal		5,647			—			5,647			—
Exploration expense		57			67			65			194
Depreciation, depletion and amortization		38,003			8,191			62,420			12,864
General and administrative expense		5,395			3,534			10,619			8,528
Credit losses and other		680			571			1,615			1,063
Total operating costs and expenses		88,386			37,838			147,170			66,484
Other operating expense, net		(303	)		—			(303	)		(5	)
Operating income		20,551			73,147			42,170			113,152
Other income (expense):
Derivative instruments gain (loss), net		31			(9,542	)		52			(41,300	)
Interest expense, net		(1,703	)		(118	)		(3,949	)		(121	)
Other expense, net		(537	)		(2,111	)		(1,677	)		(2,807	)
Total other expense, net		(2,209	)		(11,771	)		(5,574	)		(44,228	)
Income from continuing operations before income taxes		18,342			61,376			36,596			68,924
Income tax expense (benefit)		11,588			46,252			26,359			41,624
Income from continuing operations		6,754			15,124			10,237			27,300
Loss from discontinued operations, net of tax		(2	)		(20	)		(15	)		(32	)
Net income	$	6,752		$	15,104		$	10,222		$	27,268
Other comprehensive income (loss)
Currency translation adjustments		2,006			—			1,881			—
Comprehensive income	$	8,758		$	15,104		$	12,103		$	27,268
Basic net income per share:
Income from continuing operations	$	0.06		$	0.25		$	0.10		$	0.46
Loss from discontinued operations, net of tax		—			—			—			—
Net income per share	$	0.06		$	0.25		$	0.10		$	0.46
Basic weighted average shares outstanding		106,965			58,925			107,175			58,814
Diluted net income per share:
Income from continuing operations	$	0.06		$	0.25		$	0.09		$	0.45
Loss from discontinued operations, net of tax		—			—			—			—
Net income per share	$	0.06		$	0.25		$	0.09		$	0.45
Diluted weighted average shares outstanding		107,613			59,361			108,050			59,278

See notes to condensed consolidated financial statements.

3

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)

	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
Shares issued - stock-based compensation		1,090		(249	)		109		(1	)		—			—			—			108
Stock-based compensation expense		—		—			—		708			—			—			—			708
Common shares purchased		—		(1,161	)		—		—			—			(5,023	)		—			(5,023	)
Treasury stock		—		—			—		—			—			(1,003	)		—			(1,003	)
Dividend distributions		—		—			—		—			—			—			(6,717	)		(6,717	)
Other comprehensive loss		—		—			—		—			2,006			—			—			2,006
Net income		—		—			—		—			—			—			6,752			6,752
Balance at June 30, 2023		121,206		(14,208	)	$	12,121	$	355,206		$	3,060		$	(59,055	)	$	140,674		$	452,006

	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, 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 Distributions		—		—			—		—				—			(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
Shares issued - stock-based compensation		263		(54	)		27		31		—		—			—			58
Stock-based compensation expense		—		—			—		616		—		—			—			616
Treasury stock		—		—			—		—		—		(401	)		—			(401	)
Dividend Distribution																(1,943	)		(1,943	)
Net income		—		—			—		—		—		—			15,104			15,104
Balance at June 30, 2022		70,125		(11,057	)	$	7,013	$	77,919	$	—	$	(44,635	)	$	127,884		$	168,181

See notes to condensed consolidated financial statements.

4

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

	Six Months Ended June 30,
	2023			2022
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	10,222		$	27,268
Adjustments to reconcile net income to net cash provided by operating activities:
Loss from discontinued operations, net of tax		15			32
Depreciation, depletion and amortization		62,420			12,864
Bargain purchase gain		1,412			—
Deferred taxes		1,618			15,531
Unrealized foreign exchange loss		313			360
Stock-based compensation		1,254			2,264
Cash settlements paid on exercised stock appreciation rights		(233	)		(805	)
Derivative instruments (gain) loss, net		(52	)		41,300
Cash settlements paid on matured derivative contracts, net		(63	)		(33,559	)
Cash settlements paid on asset retirement obligations		(374	)		—
Credit losses and other		1,615			1,063
Other operating loss, net		62			5
Operational expenses associated with equipment and other		(1,196	)		718
Change in operating assets and liabilities:
Trade receivables		(5,208	)		(47,810	)
Accounts with joint venture owners		21,746			10,283
Other receivables		(1,868	)		(943	)
Crude oil inventory		(7,465	)		(12,274	)
Prepayments and other		(69	)		1,570
Value added tax and other receivables		(2,302	)		(2,249	)
Other long-term assets		1,508			(1,072	)
Accounts payable		(10,897	)		(857	)
Foreign income taxes receivable/payable		15,344			26,093
Deferred tax liability		(3,081	)		—
Accrued liabilities and other		(7,137	)		29,263
Net cash provided by (used in) continuing operating activities		77,584			69,045
Net cash used in discontinued operating activities		(15	)		(38	)
Net cash provided by (used in) operating activities		77,569			69,007
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures		(54,832	)		(60,278	)
Net cash provided by (used in) continuing investing activities		(54,832	)		(60,278	)
Net cash used in discontinued investing activities		—			—
Net cash provided by (used in) investing activities		(54,832	)		(60,278	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock		382			257
Dividend distribution		(13,452	)		(3,872	)
Treasury shares		(11,403	)		(788	)
Deferred financing costs		(30	)		(1,451	)
Payments of finance lease		(3,379	)		(68	)
Net cash provided by (used in) in continuing financing activities		(27,882	)		(5,922	)
Net cash used in discontinued financing activities		—			—
Net cash provided by (used in) in financing activities		(27,882	)		(5,922	)
Effects of exchange rate changes on cash		(285	)		—
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		(5,430	)		2,807
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD		59,776			72,314
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	54,346		$	75,121

See notes to condensed consolidated financial statements.

5

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)

	Six Months Ended June 30,
	2023		2022
	(in thousands)
Supplemental disclosure of cash flow information:
Interest paid, net of amounts capitalized	$	5,177	$	113
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	26,746	$	29,155
Recognition of right-of-use finance lease assets and liabilities	$	3,273	$	1,851

See notes to condensed consolidated financial statements.

6

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, natural gas and natural gas liquids ("NGLs") properties. As operator, the Company has production operations and conducts exploration activities in Gabon and Canada and hold interests in two production sharing contracts (“PSCs”) in Egypt. The Company 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 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), 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 unaudited condensed consolidated financial statements (“Financial Statements”) are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results expected for the full year.

These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, which includes a summary of the significant accounting policies.

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 per day through December 2023 by various members in addition to the 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 8 MBbls per day. On June 5, 2023, OPEC meeting Saudi Arabia agreed to an additional 1 MMBbls per day for July 2023 but could be extended. In addition, members of OPEC+ agreed to extend the group's existing supply cuts of 3.7 MMBbls per day for another year ( December 2024). The Company has not received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiatives. 

The average Brent crude oil price for the three months ended June 30, 2023 was $78 per barrel. The average price for all 2022 and 2023 periods are summarized below:

Average Brent Prices	2023		2022
First Quarter	$	81.07	$	100.87
Second Quarter	$	77.99	$	113.84
Third Quarter	$	—	$	100.71
Fourth Quarter	$	—	$	88.72

During the year ended December 31, 2022 and continuing into 2023, the lead times associated with obtaining materials to support its operations and drilling activities have lengthened and, in some cases, prices for fuel, services 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 commodity price environment is still favorable and the Company has not experienced material disruptions to its operations, any factors 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.

7

 

Principles of consolidation – The accompanying unaudited condensed consolidated 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 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 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 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 June 30, 2023 and 2022 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”) and representing bank guarantees for customs clearance in Gabon. For Canada, approximately $0.1 million has been set aside as of June 30, 2023 related to property taxes reserved for Mountain View County. Long-term amounts at June 30, 2023 and 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 June 30,
	2023		2022
	(in thousands)
Cash and cash equivalents	$	46,186	$	53,062
Restricted cash - current		113		216
Restricted cash - non-current		1,779		1,752
Abandonment funding		6,268		20,091
Total cash, cash equivalents and restricted cash	$	54,346	$	75,121

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 of the Economic and Monetary Community of Central Africa (CEMAC) of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Etame PSC provides these payments must be denominated in USD and the CEMAC regulations provide for establishment of a USD account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests 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 payment for the years 2019 through 2022 totaling $5.8 million, net to VAALCO based on the 2018 abandonment study. On January 12, 2023, after continued discussions with various BEAC and government officials, the Company was allowed to 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.

8

 

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 March 2023. The balance remained unchanged during the second quarter of 2023.

The Company is working on an updated abandonment study with Directorate of Hydrocarbons in Gabon and on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC. 

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. 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, see allowance for credit losses below.

Accounts Receivable, net– The Company’s trade accounts receivable results from sales of crude oil, natural gas, and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses below.

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 produced by the Company was not compatible with the crude oil requirements of the refinery, the Company entered into two contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that produced the compatible oil the refinery required and another contract with the refinery itself to deliver the crude oil. Under the contract with the 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 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 June 30, 2023 condensed consolidated balance sheet are current receivables in the "other, net" line item of approximately $19.7 million for amounts due to the Company from the refinery for 228 MBbls delivered to the refinery, and $19.7 million current liability included in the "Account payable" line item for amounts due to the oil supplier for 228 MBbls of purchased crude oil from the supplier in the second half of 2022 and the first quarter of 2023. A $1.9 million payment was received in July for the receivable related to March deliveries.

On January 19, 2022, TransGlobe’s West Gharib, West Bakr and 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. At June 30, 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 establish third party cargoes to pay the back dated receivable as well as allow third party cargoes against current production

For credit losses associated with other receivables, see allowance for credit losses below.

Value added tax and other receivables, net – 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.

9

 

As of June 30, 2023, the outstanding VAT receivable balance, excluding the allowance, was approximately $24.3 million ($15.8 million, net to VAALCO). As of June 30, 2023, the exchange rate was XAF 602.552 = $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 the “Value added tax and 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. The Company is in discussions with the Ministry of Economy and Ministry of Hydrocarbon to obtain a suitable payment plan to address both the back dated VAT and the Government supplied refinery Sogara. VAALCO is in an advanced stage of negotiations for a payment plan resolving this. 

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. 

The Company estimates the current expected credit losses based primarily using 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 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. During the three months ended June 30, 2023, there was no additional provision recorded.

Also on January 1, 2023, the Company transferred its $0.3 million provision related to accounts with joint venture owners from an allowance for bad debt account to an expected credit loss account. An additional $0.2 million was transferred during the second quarter of 2023. As of  June 30, 2023, the Company has established a credit loss allowance for the full $0.5 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  June 30, 2023, the Company recognized an additional $0.5 million related to its Value added tax with Gabon. During the six months ended June 30, 2023, the Company recognized an additional $1.1 million provision related to its Value added tax with Gabon.

With respect to the Company’s receivable from the refinery and 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 the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to the realization of the past due balances.

10

 

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands)
Allowance for credit losses and other
Balance at beginning of period	$	(12,832	)	$	(6,135	)	$	(8,704	)	$	(5,741	)
Credit loss charges and other, net of receipts		(680	)		(571	)		(1,615	)		(1,063	)
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023		—			—			(3,120	)		—
Foreign currency gain (loss)		(7	)		317			(80	)		415
Balance at end of period	$	(13,519	)	$	(6,389	)	$	(13,519	)	$	(6,389	)

Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon, inventories represent the Company's share of crude oil produced and stored, but unsold at the end of the period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. At June 30, 2023, the Company had 206,136 Bbls of crude oil underlift in Egypt. The Company resolved to sell domestically in the second quarter a proportion of its underlift from the second quarter to ensure an export cargo in August that has now been confirmed with terminal operator. Direct sales to Egypt were higher in the second quarter because of this but allows the Company to thrash out receivable settlements by way of offsets against sister EGPC companies that the Company has utilized in the drilling campaign. The export cargo in the third quarter will allow the Company to receive cash offshore and the Company is currently marketing this cargo with several traders.

Prepayments and Other – Included in “Prepayments and other” line item of the Company’s June 30, 2023 condensed consolidated balance sheet are $2.5 million of prepayments related to fixed assets, $2.7 million of prepayments related to royalties in Gabon, $1.5 million in Gabon and corporate prepaid insurance, $4.0 million related to prepaid fuel in Egypt, $1.9 million in Egyptian advances to contractors, $0.4 million in prepaid Egypt payroll, and $5.1 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, 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. The amount 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. 

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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, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, 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.

Impairment – The Company reviews the crude oil, 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 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, 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, 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, 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  October 13, 2022, the Company and AcquireCo, an indirect wholly-owned subsidiary of the Company, completed the business acquisition of TransGlobe and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement on  July 13, 2022. The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. To allocate the purchase price, the Company developed fair value models. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 3 for further discussion.

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

Asset retirement obligations (“ARO”) – The Company has obligations to remove tangible equipment and restore land or seabed at the end of crude oil, 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, 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.

12

 

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, 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, 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, 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 13 for further discussion.

Revenue recognition – The Company's revenues are derived primarily from contracts with customers. Royalties are considered a cost 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 recognized when the Company satisfies a performance obligation 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 customer and the customer taking physical possession. VAALCO mainly satisfies its performance obligations at a point in time and the amounts of revenues recognized relating to performance obligations satisfied over time are not significant. See Note 6 for further discussion.

In connection with the acquisition of TransGlobe on October 13, 2022, the Company has elected to apply its policy regarding shipping and handling costs and are presenting these costs net within revenue in the consolidated statements of operations and comprehensive income. In addition, the Company has elected to recognize revenue from oil, natural gas and NGL’s based on the Company’s net working interest, less royalties on the consolidated statements of operations and comprehensive income. Any imbalances from an underlift or overlift position are valued based on the 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 15 for further discussion.

13

 

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.” 

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, 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. The Company also records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil in Gabon which results due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted.

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

In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, the Company has not recognized deferred tax assets. Should the expectations change regarding the expected future tax consequences, the Company may be required to record additional deferred taxes that could have a material effect on the condensed consolidated financial position and results of operations. See Note 16 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 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 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).

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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, 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 the Company's review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.

Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, accrued liabilities, liabilities for SARs. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using Level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance sheet while the long-term portion is reported in “Other long-term liabilities”. With respect to 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 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 June 30, 2023
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Assets
Derivative asset	Prepayments and other	$	—	$	158	$	—	$	158
		$	—	$	158	$	—	$	158
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	196	$	—	$	196
		$	—	$	196	$	—	$	196

`		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. 

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Other comprehensive income – All of the Company’s other comprehensive income arises from the Company'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 June 30, 2023 was 0.738 USD and 0.755, respectively.

2. NEW ACCOUNTING STANDARDS 

Adopted

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. ASU 2016-13 is effective for 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 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 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”). The Company recorded an ECL allowance of $3.1 million as an opening balance adjustment to retained earnings at January 1, 2023. See Note 1 for further details.

Not Yet Adopted

In  March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848),” which provides optional expedients and exceptions for applying U.S. GAAP to debt contracts, receivables, leases, derivatives, and other contracts impacted by reference rate reform and other transactions affected by the cessation of the LIBOR. The expiration date of ASU 2020-04 was  December 31, 2022.

In  December 2022, the FASB issued ASU 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848,” to extend the expiration date of Topic 848 through  December 31, 2024. The expedients, if adopted, can be applied prospectively. As the Company implements alternative rates from LIBOR into the Company's current contracts, it is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is discontinued.

3. ACQUISITIONS AND DISPOSITIONS

TransGlobe Merger

On October 13, 2022, the Company and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the 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”).

16

 

At the effective time of the Arrangement and pursuant to the 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 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 Arrangement Agreement.

Prior to the 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 is the accounting acquiror. The purchase accounting for the business combination has not been completed. 

During the three months ended  June 30, 2023 the deferred tax liability in Egypt did not change. During the six months ended June 30, 2023, the deferred tax liability in Egypt was increased by $1.4 million, respectively, as of the date of the Arrangement. This resulted in a decrease to the bargain purchase gain of a corresponding $1.4 million for the six months ended June 30, 2023, and is reflected in VAALCO's condensed consolidated statements of operations in the line, “Other expense, net”. 

The actual impact of the Arrangement was an increase to “Crude oil, natural gas and NGLs sales” of $75.0  million and $1.7  million of “Net income” in the condensed consolidated statements of operations and comprehensive income for the six months ended June 30, 2023. The impact for the three months ended  June 30, 2023 was an increase to “Crude oil, natural gas and NGLs sales” of $31.3  million and $(8.0)  million of “Net Loss” in the condensed consolidated statements of operations and comprehensive income.

	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			Measurement Period Adjustment			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

 

All assets and liabilities associated with TransGlobe, including crude oil, 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,  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 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 adjustment factors based on reserve category discount rates. Other estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The purchase price allocation is preliminary pending final determination of 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, an initial $10.8 million bargain purchase gain was recognized. As a result of the measurement period adjustment, the initial bargain purchase gain has been reduced to $9.4 million. The bargain purchase gain was due to the decrease in the share price of VAALCO stock from the time period when the arrangement agreement was signed,  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 same. 

The unaudited pro forma results presented below have been prepared to give the effect of the TransGlobe Arrangement discussed above on the Company’s results for the three and six months ended June 30, 2022, as if the Arrangement had been consummated on January 1, 2021. The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the TransGlobe Arrangement had been completed on such date or project the Company’s results of operations for any future date or period.

	Three Months Ended June 30,			Six Months Ended June 30,
	2022			2022
	(in thousands)			(in thousands)
Pro forma (unaudited):
Crude oil, natural gas and natural gas liquids sales	$	183,665	(a)	$	304,792	(a)
Operating income	$	110,091	(b)	$	171,518	(d)
Net income	$	41,818	(c)	$	72,857	(e)
Basic net income per share:	$	0.39		$	0.67
Basic weighted average shares outstanding		108,232			108,121
Diluted net income per share:	$	0.38		$	0.67
Diluted weighted average shares outstanding		108,668			108,585

(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 June 30, 2022 reclassifies depreciation expense, 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 three months ended June 30, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense.
(d)	The unaudited pro forma operating income for the six months ended June 30, 2022 removes the $26.0 million impairment reversal recorded by TransGlobe in 2022, reclassifies depreciation expense, 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.
(e)	The unaudited pro forma net income for the six months ended June 30, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense.

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 consolidated balance sheets. The operating results of the Angola 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 Angola segment from the cash flows from continuing operations for all periods presented in the Company’s consolidated statements of cash flows. During the three and six months ended June 30, 2023 and 2022, the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

18

 

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 and six months ended June 30, 2023, the Yemen segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

4. SEGMENT INFORMATION 

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

Segment activity of continuing operations for the three and six months ended June 30, 2023 and 2022 as well as long-lived assets and segment assets at June 30, 2023 and December 31, 2022 are as follows:

	Three Months Ended June 30, 2023
(in thousands)	Gabon			Egypt			Canada		Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	77,924		$	21,308		$	10,008	$	—		$	—		$	109,240
Operating costs and expenses:
Production expense		23,931			11,089			3,255		386			(57	)		38,604
FPSO Demobilization - Norms Waste Disposal		5,647			—			—		—			—			5,647
Exploration expense		43			14			—		—			—			57
Depreciation, depletion and amortization		19,457			13,757			4,747		—			42			38,003
General and administrative expense		318			202			—		87			4,788			5,395
Credit losses and other		518			—			—		162			—			680
Total operating costs and expenses		49,914			25,062			8,002		635			4,773			88,386
Other operating income (expense), net		(62	)		(241	)		—		—			—			(303	)
Operating income		27,948			(3,995	)		2,006		(635	)		(4,773	)		20,551
Other income (expense):
Derivative instruments loss, net		—			—			—		—			31			31
Interest (expense) income, net		(1,376	)		(503	)		—		—			176			(1,703	)
Other (expense) income, net		(619	)		—			1		—			81			(537	)
Total other expense, net		(1,995	)		(503	)		1		—			288			(2,209	)
Income (loss) from continuing operations before income taxes		25,953			(4,498	)		2,007		(635	)		(4,485	)		18,342
Income tax (benefit) expense		16,251			4,261			—		—			(8,924	)		11,588
Income (loss) from continuing operations		9,702			(8,759	)		2,007		(635	)		4,439			6,754
Loss from discontinued operations, net of tax		—			—			—		—			(2	)		(2	)
Net income (loss)	$	9,702		$	(8,759	)	$	2,007	$	(635	)	$	4,437		$	6,752
Consolidated capital expenditures	$	1,375		$	8,526		$	6,491	$	—		$	36		$	16,427

19

 

	Six Months Ended June 30, 2023
(in thousands)	Gabon			Egypt			Canada			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	114,661		$	56,092		$	18,890		$	—		$	—		$	189,643
Operating costs and expenses:
Production expense		38,346			22,199			5,509			748			2			66,804
FPSO Demobilization - Norms Waste Disposal		5,647			—			—			—			—			5,647
Exploration expense		51			14			—			—			—			65
Depreciation, depletion and amortization		29,302			24,552			8,458			—			108			62,420
General and administrative expense		936			381			—			216			9,086			10,619
Credit losses and other		1,453			—			—			162			—			1,615
Total operating costs and expenses		75,735			47,146			13,967			1,126			9,196			147,170
Other operating income, net		(62	)		(241	)		—			—			—			(303	)
Operating income (loss)		38,864			8,705			4,923			(1,126	)		(9,196	)		42,170
Other income (expense):
Derivative instruments gain, net		—			—			—			—			52			52
Interest (expense) income, net		(2,883	)		(1,311	)		(4	)		—			249			(3,949	)
Other income (expense), net		(102	)		—			1			(1	)		(1,575	)		(1,677	)
Total other expense, net		(2,985	)		(1,311	)		(3	)		(1	)		(1,274	)		(5,574	)
Income (loss) from continuing operations before income taxes		35,879			7,394			4,920			(1,127	)		(10,470	)		36,596
Income tax expense (benefit)		22,829			9,253			—			—			(5,723	)		26,359
Income (loss) from continuing operations		13,050			(1,859	)		4,920			(1,127	)		(4,747	)		10,237
Loss from discontinued operations, net of tax		—			—			—			—			(15	)		(15	)
Net income (loss)	$	13,050		$	(1,859	)	$	4,920		$	(1,127	)	$	(4,762	)	$	10,222
Consolidated capital expenditures	$	5,064		$	20,097		$	16,656		$	—		$	36		$	41,852

20

 

	Three Months Ended June 30, 2022
(in thousands)	Gabon			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil and natural gas sales	$	110,985		$	—		$	—		$	110,985
Operating costs and expenses:
Production expense		25,360			175			(60	)		25,475
Exploration expense		67			—			—			67
Depreciation, depletion and amortization		8,173			—			18			8,191
General and administrative expense		565			110			2,859			3,534
Bad debt expense and other		571			—			—			571
Total operating costs and expenses		34,736			285			2,817			37,838
Other operating income (expense), net		—			—			—			—
Operating income		76,249			(285	)		(2,817	)		73,147
Other income (expense):
Derivative instruments loss, net		—			—			(9,542	)		(9,542	)
Interest (expense) income, net		(158	)		—			40			(118	)
Other (expense) income, net		(856	)		(1	)		(1,254	)		(2,111	)
Total other expense, net		(1,014	)		(1	)		(10,756	)		(11,771	)
Income from continuing operations before income taxes		75,235			(286	)		(13,573	)		61,376
Income tax (benefit) expense		36,423			1			9,828			46,252
Income from continuing operations		38,812			(287	)		(23,401	)		15,124
Loss from discontinued operations, net of tax		—			—			(20	)		(20	)
Net income	$	38,812		$	(287	)	$	(23,421	)	$	15,104
Consolidated capital expenditures (1)	$	38,102		$	—		$	67		$	38,169

	Six Months Ended June 30, 2022
(in thousands)	Gabon			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil and natural gas sales	$	179,641		$	—		$	—		$	179,641
Operating costs and expenses:
Production expense		43,441			394			—			43,835
Exploration expense		194			—			—			194
Depreciation, depletion and amortization		12,826			—			38			12,864
General and administrative expense		1,158			209			7,161			8,528
Credit losses and other		1,063			—			—			1,063
Total operating costs and expenses		58,682			603			7,199			66,484
Other operating income (expense), net		(5	)		—			—			(5	)
Operating income		120,954			(603	)		(7,199	)		113,152
Other income (expense):
Derivative instruments loss, net		—			—			(41,300	)		(41,300	)
Interest (expense) income, net		(164	)		—			43			(121	)
Other (expense) income, net		(1,494	)		(2	)		(1,311	)		(2,807	)
Total other expense, net		(1,658	)		(2	)		(42,568	)		(44,228	)
Income from continuing operations before income taxes		119,296			(605	)		(49,767	)		68,924
Income tax (benefit) expense		49,256			1			(7,633	)		41,624
Income from continuing operations		70,040			(606	)		(42,134	)		27,300
Loss from discontinued operations, net of tax		—			—			(32	)		(32	)
Net income	$	70,040		$	(606	)	$	(42,166	)	$	27,268
Consolidated capital expenditures (1)	$	69,882		$	—		$	67		$	69,949

21

 

(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Corporate and Other		Total
Long-lived assets from continuing operations:
As of June 30, 2023	$	193,501	$	165,813	$	111,677	$	10,000	$	749	$	481,740
As of December 31, 2022 (1)		213,204	$	168,012	$	103,263	$	10,000	$	793	$	495,272

(1) - Includes assets acquired in the TransGlobe acquisition

(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Corporate and Other		Total
Total assets from continuing operations:
As of June 30, 2023	$	384,554	$	270,653	$	118,604	$	11,144	$	44,058	$	829,013
As of December 31, 2022 (1)		395,393	$	293,640	$	110,071	$	10,861	$	45,676	$	855,641

(1) - Includes assets acquired in the 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 was previously party to a COSPA with ExxonMobil Sales and Supply LLC (“Exxon”) that covered sales from February 2020 through July 2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. This COSPA has been terminated.

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 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 an initial aggregate maximum principal amount available of up to $50.0 million. In connection with the 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 crude oil produced from the Etame G4-160 Block, offshore Gabon during the period from August 1, 2022 until the Final Maturity Date of 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.

For the three and six months ended June 30, 2023 sales of crude oil to Glencore made up 100% of Etame revenues. For the three and six months ended June 30, 2022, sales of crude oil to ExxonMobil Sales and Supply LLC made up 100% of Etame revenues. For the three months ended June 30, 2023, the EGPC covered 100% of the Company's crude oil sales in Egypt. For the six months ended June 30, 2023, Mercuria covered 100% of the Company’s crude oil sales in Egypt in the first quarter, while the EGPC covered 100% of sales in the second quarter. For the three and six months ended June 30, 2023, revenues in Canada were concentrated in three separate customers. These customers were Plains Midstream (50.9%), AltaGas (19.1%), and PetroGas Energy (18.60%). Concentrations of accounts receivable are similar to the revenue percentages.

22

 

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 to net income used in calculating EPS as well as a reconciliation from basic to diluted shares follows: 

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands)
Net income (loss) (numerator):
Income (loss) from continuing operations	$	6,754		$	15,124		$	10,237		$	27,300
Income from continuing operations attributable to unvested shares		(27	)		(229	)		(15	)		(381	)
Numerator for basic		6,727			14,895			10,222			26,919
Loss from continuing operations attributable to unvested shares		—			1			(41	)		2
Numerator for dilutive	$	6,727		$	14,896		$	10,181		$	26,921
Loss from discontinued operations, net of tax	$	(2	)	$	(20	)	$	(15	)	$	(32	)
Loss from discontinued operations attributable to unvested shares		—			—			—			—
Numerator for basic		(2	)		(20	)		(15	)		(32	)
(Income) loss from discontinued operations attributable to unvested shares		—			—			—			—
Numerator for dilutive	$	(2	)	$	(20	)	$	(15	)	$	(32	)
Net income (loss)	$	6,752		$	15,104		$	10,222		$	27,268
Net income attributable to unvested shares		(27	)		(229	)		(56	)		(381	)
Numerator for basic		6,725			14,875			10,166			26,887
Net (income) loss attributable to unvested shares		27			1			41			2
Numerator for dilutive	$	6,752		$	14,876		$	10,125		$	26,889
Weighted average shares (denominator):
Basic weighted average shares outstanding		106,965			58,925			107,175			58,814
Effect of dilutive securities		648			436			875			464
Diluted weighted average shares outstanding		107,613			59,361			108,050			59,278
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		431			251			238			154

6. REVENUE

Gabon

Revenues from contracts with customers are generated from sales in Gabon pursuant to 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 or COSMAs. See Note 4 under “Information about the Company’s most significant customers” for further discussion.

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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 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), 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 sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. Historically, 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 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 about applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, the Company deemed this situation to be characterized as a fixed price situation.

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

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

With respect to the government’s share of Profit Oil, the Etame PSC provides that the corporate income tax liability may be satisfied through the payment of Profit Oil. In the condensed consolidated statements of operations 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 the 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.

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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 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 $16.7 million foreign income tax payable as of  June 30, 2023 related to Gabon. As of December 31, 2022, the Company had a foreign taxes receivable of $2.8 million, as the Gabonese government lifted more oil-in-kind than what was 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 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 June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Revenues from customer contracts:	(in thousands)
Sales under the COSPA or COSMA	$	87,478		$	125,143		$	130,079		$	201,629
Other items reported in revenue not associated with customer contracts:
Carried interest recoupment		2,212			2,371			2,212			3,483
Royalties		(11,766	)		(16,529	)		(17,630	)		(25,471	)
Net revenues	$	77,924		$	110,985		$	114,661		$	179,641

Egypt

Revenues from sales in Egypt are generally made through direct sales to EGPC or through contracts with customers pursuant to COSPAs 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.

Customer sales generally occur daily 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 the EGPC storage facility, and the Company has elected to sell domestically to EGPC. When sales are made through a 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. 

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Egypt production is based on Dated Brent prices, less a quality differential (currently around 4.9%) and is shared with the Egyptian government through the PSCs and their government take. 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 production (take)will 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 because of direct marketing to international purchasers. Depending on the Company's assessment of the credit of crude oil cargo buyers, customers  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 one to two months from delivery. 

In some instances, TPI will borrow or loan production volumes 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 June 30,			Six Months Ended June 30,
	2023			2023
Revenues from customer contracts:	(in thousands)
Gross sales	$	50,201		$	104,822
Royalties		(28,892	)		(48,232	)
Selling costs		(1	)		(498	)
Net revenues	$	21,308		$	56,092

Canada

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. 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 to in exchange for transferring promised goods to a customer and 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 revenue net of royalties.

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Customer sales generally occur daily 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 types 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 June 30,			Six Months Ended June 30,
	2023			2023
Revenues from customer contracts:	(in thousands)
Oil revenue	$	8,325		$	14,979
Gas revenue		703			1,661
NGL revenue		1,885			4,348
Royalties		(905	)		(2,098	)
Net revenues	$	10,008		$	18,890

7. CRUDE OIL, 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 June 30, 2023			As of December 31, 2022
	(in thousands)
Crude oil, natural gas and NGLs properties and equipment - successful efforts method:
Wells, platforms and other production facilities	$	1,446,801		$	1,406,888
Work-in-progress		—			—
Undeveloped acreage		54,346			56,251
Equipment and other		43,835			38,796
		1,544,982			1,501,935
Accumulated depreciation, depletion, amortization and impairment		(1,063,242	)		(1,006,663	)
Net crude oil, natural gas and NGLs properties, equipment and other	$	481,740		$	495,272

Etame Marin Block PSC

On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the “Etame Consortium”), received a Presidential Decree for an extension (“PSC Extension”) to the Etame Consortium to operate in the Etame Marin block. The PSC Extension extends the term to operate until September 17, 2028. The PSC Extension also grants the Etame Consortium the right for two additional extension periods of five years each. 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.

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

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Egypt PSCs

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 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 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 of royalty on 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 the Company's PSCs.

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	%

(1) - Represents the year acquired by TransGlobe, prior to the Arrangement.

*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

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Equatorial Guinea PSC

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 first 10,000 bopd, and 11% for the 10,000 bopd to 25,000 bopd tranche. The Government of Equatorial Guinea'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 Government of Equatorial Guinea'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. 

Proved Properties

The Company reviews the crude oil, 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, 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 three months ended June 30, 2023 that would cause the Company to believe the value of crude oil, natural gas and NGLs producing properties should be impaired. Factors considered included higher forward prices from June 30, 2023 and capital expenditures in the period related to its reserves in Gabon, Egypt and Canada. 

Undeveloped Leasehold Costs 

Equatorial Guinea

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 the Company's appointment as the operator 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”) if 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 non-defaulting parties assigned the defaulting party’s interest to the non-defaulting parties as required by the Joint Operating Agreement. As a result, VAALCO’s working interest increased to 45.9% when the EG MMH approved the fourth amendment to the production sharing contract. In February of 2023, the Company 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 at first commercial production of the Block.

The Company has completed a feasibility study of the development concept of the Venus discovery on Block P. On September 16, 2022, the EG MMH approved the submitted plan of development. Final documents to affect the plan of development are subject to EG MMH approval. The 2023 budget for the plan was delivered on October 12, 2022 to the MMH and 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 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 for the area associated with the Venus development. As of June 30, 2023, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. 

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Gabon

As a result of the PSC extension discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $6.7 million of the share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame Marin block PSC. As a result of discovering reserves in connection with drilling the South East Etame 4H development well in March 2020, $2.3 million of costs were transferred to proved leasehold costs leaving a remaining $11.5 million in unproved leasehold costs. In connection with the Sasol Acquisition discussed under Note 3, $2.2 million of reserves were attributed to undeveloped properties. The balance of undeveloped leasehold costs related to the Etame Marin block at June 30, 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 June 30, 2023, the undeveloped leasehold costs for Egypt was $13.9 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 expense, net” line item of the unaudited condensed consolidated statements of operations and comprehensive income but were not material for the three and six months ended June 30, 2023 and 2022.

8. DERIVATIVES

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. See the table below for the list of outstanding contracts as of June 30, 2023:

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

While these 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 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 purposes. 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 Company has not yet drawn down on its available facility.

The 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 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" on the unaudited condensed consolidated balance sheets.

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

		Three Months Ended June 30,						Six Months Ended June 30,
Derivative Item	Statements of Operations Line	2023			2022			2023			2022
		(in thousands)						(in thousands)
Commodity derivatives	Cash settlements paid on matured derivative contracts, net	$	(4	)	$	(21,059	)	$	(63	)	$	(33,559	)
	Unrealized gain (loss)		35			11,517			115			(7,741	)
	Derivative instruments gain (loss), net	$	31		$	(9,542	)	$	52		$	(41,300	)

9. CURRENT ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:

	As of June 30, 2023		As of December 31, 2022
	(in thousands)
Accrued accounts payable invoices	$	21,480	$	28,360
Gabon DMO, PID and PIH obligations		12,782		10,509
Capital expenditures		19,770		26,618
Stock appreciation rights – current portion		32		570
Accrued wages and other compensation		2,726		8,161
ARO Obligation		5,729		306
Egypt modernization payments		9,373		9,933
Excess cost oil payable		8,099		—
Other		4,113		6,935
Total accrued liabilities and other	$	84,104	$	91,392

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 (prior to the decommissioning of the FPSO Nautipa which occurred in February 2023), and the estimate used for this purpose is approximately $81.3 million ($47.8 million, net to VAALCO) on an undiscounted basis. The abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the Etame PSC. At  June 30, 2023, the balance of the abandonment fund was $10.7 million ($6.3 million, net to VAALCO) on an undiscounted 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.

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 March 2023. No activity was noted in the abandonment funding account during the second quarter of 2023. 

FPSO charter

In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter could be extended for two one-year periods beyond September 2020. These elections were made, and the charter was extended through September 2022. On September 9, 2022, the Company signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022 and ratified certain decommissioning and demobilization items associated with exiting the contract.

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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 on a gross basis, $8.9 million net to 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 settle on the Company’s restricted cash balances associated with the FPSO. In the second quarter of 2023, it was determined that there was more waste than anticipated connected to the FPSO from VAALCO's usage. As such, VAALCO incurred an additional $5.6 million in decommissioning fees, which was reported as a separate line item on the income statement. 

During the second quarter of 2023, the Joint Operating Group were informed by BW Offshore the supplier of the former FPSO that waste disposal of naturally occurring radioactive material was present in the final volumes and tanks on the vessel as is typical. The JOA have an obligation to lift and properly dispose of this waste. The Company has provided for an accrual for the collection and disposal of the waste via tank cleaning activities that will occur in September and October 2023. The cost is expected to be around $9.6 million gross ($5.6 million net to VAALCO).

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. The Company is working with the 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 received the findings from this audit and has responded to the audit findings and are working with the government of Gabon on the results of the 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.

Dividend Policy

On November 3, 2021, the Company announced that the Company’s board of directors adopted a cash dividend policy. 

On May 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share, which was paid on  June 23, 2023 to stockholders of record at the close of business on May 24, 2023. On August 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on September 22, 2023 to stockholders of record at the close of business on August 25, 2023. 

In connection with the RBL facility, discussed in Note 11 to the Financial Statements, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. If 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 to make distributions, buyback shares, or repurchase stock. For the six months ended  June 30, 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 considering 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 up to 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. 

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The following table shows the repurchases of equity securities related to the share repurchase program after March 31, 2023 through June 30, 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
April 1, 2023 - April 30, 2023		303,969	$	4.94		303,969	$	21,003,245
May 1, 2023 - May 31, 2023		362,843	$	4.14		362,843	$	19,502,740
June 1, 2023 - June 30, 2023		494,164	$	4.05		494,164	$	17,504,007
Total		1,160,976				1,160,976

The following table shows the repurchases of equity securities related to the share repurchase program after June 30, 2023 through  August 4, 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
July 1, 2023 - July 31, 2023		505,720		$3.96		505,720		$15,504,180
August 1, 2023 - August 4, 2023		98,411		$4.29		98,411		$15,082,133
Total		604,131				604,131

The actual timing number and value of shares repurchased under the share buyback program will depend on several 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 condition's 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 $26.8 million at June 30, 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 $17.5 million was recorded in "Other long-term liabilities". 

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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 June 30, 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 because 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 June 30, 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 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 Sogara 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 two contracts (buy/sell arrangements) to fulfill its domestic market needs obligation under the Etame PSC. One contract is to purchase oil from another provider (currently Perenco – the supplier) that produces the compatible oil to meet the needs of the 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. At June 30, 2023, the amount due to the Company from the refinery is $19.7 million. A separate credit loss of $3.1 million has been provided for. 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 Company. The Company expects to recover the full amount receivable owed to it for both the VAT receivable and receivable under the oil supply arrangement, but the terms of recovery have not fully been finalized. 

11. DEBT

As of  June 30, 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 reduced by $6.25 million.

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. 

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).

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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 June 30, 2023, the Company's borrowing base was $50.0 million. The amount the Company can borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. Regarding the requirement, the Company must 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 June 30, 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 $1.7 million, ($2.1 million net of accumulated amortization of $0.4 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

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.

Operating leases

The Company is currently a party to several operating lease agreements for the corporate office, rental of marine vessels and equipment and a drilling rig used in the Company’s Egyptian operations. The duration for these agreements ranges from 5 to 21 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for marine vessels, and certain equipment used in the joint operations includes the gross amount of the lease components.

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

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Financing leases

The Company is currently a party to several financing lease agreements for the FSO and generators used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. The duration for these agreements ranges from 4 to 111 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities.

All leases

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

For the three and six months ended June 30, 2023 and 2022, the components of the lease costs and the supplemental information were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Lease cost:	(in thousands)
Finance lease cost (1)	$	4,115	$	98	$	8,480	$	164
Operating lease cost		339		4,265		922		8,461
Short-term lease cost (2)		1,660		199		3,020		1,213
Variable lease cost (3)		—		1,909		—		3,247
Total lease expense		6,114		6,471		12,422		13,085
Lease costs capitalized		7		651		55		1,423
Total lease costs	$	6,121	$	7,122	$	12,477	$	14,508

	Six Months Ended June 30,
	2023			2022
Other information:
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash flows attributable to finance leases (in thousands)	$	3,379		$	26
Weighted-average remaining lease term (in years)		8.96			5.17
Weighted-average discount rate		8.11	%		3.54	%
Operating cash flows attributable to operating leases (in thousands)	$	423		$	12,816
Weighted-average remaining lease term (in years)		0.95			0.70
Weighted-average discount rate		10.33	%		5.62	%

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

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

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

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The table below describes the presentation of the total lease cost on the Company’s unaudited condensed consolidated statements of 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(in thousands)
Finance lease cost	$	2,376	$	57	$	5,001	$	96
Production expense		1,208		3,720		2,494		7,558
General and administrative expense		52		47		98		63
Lease costs billed to the joint venture owners		2,481		2,884		4,849		5,886
Total lease expense		6,117		6,708		12,442		13,603
Lease costs capitalized		4		414		35		905
Total lease costs	$	6,121	$	7,122	$	12,477	$	14,508

The following table describes the future maturities of the Company’s lease liabilities at June 30, 2023:

	Operating Leases		Finance Leases
Year	(in thousands)
2023	$	1,173	$	7,287
2024		672		14,448
2025		32		16,202
2026		—		16,478
2027		—		15,023
Thereafter		—		51,527
		1,877		120,965
Less: imputed interest		80		33,425
Total lease liabilities	$	1,797	$	87,540

Under the joint operating agreements, other joint venture owners are obligated to fund $49.8 million of the $122.8 million in future lease liabilities.

13. ASSET RETIREMENT OBLIGATIONS 

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

(in thousands)	As of June 30, 2023			As of December 31, 2022
Beginning balance	$	42,001		$	40,694
Accretion		1,118			1,958
Additions		—			6,134
Revisions		5,726			(43	)
Settlements		(374	)		(6,577	)
Foreign currency gain (loss)		216			(165	)
Ending balance	$	48,687		$	42,001

 

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

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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. As a result of the expected timing of the end of the FPSO contract, included in the line item "Accrued liabilities and other" in the unaudited condensed consolidated balance sheet is $5.6 million of costs associated with the retirement obligation as of June 30, 2023. The accrual is primarily related to the FPSO waste disposal discussed in detail in the commitments and contingencies footnote. 

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.

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 June 30, 2023 and 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. No shares of preferred stock were issued and outstanding as of June 30, 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 up to 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.

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The below table shows the repurchases of the Company's equity securities during the three months ended June 30, 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
April 1, 2023 - April 30, 2023		303,969	$	4.94		303,969	$	21,003,245
May 1, 2023 - May 31, 2023		362,843	$	4.14		362,843	$	19,502,740
June 1, 2023 - June 30, 2023		494,164	$	4.05		494,164	$	17,504,007
Total		1,160,976				1,160,976

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 the Company's financial statements as they reduce the number of shares that would have been issued upon vesting. See Note 15 for further discussion.

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 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At June 30, 2023, under the 2020 Plan, 1,718,603 shares were available for future grants.

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

As referenced in the table below, the Company records compensation expenses 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 six months ended June 30, 2023, the Company settled in cash $0.2 million for stock appreciation rights and received $0.4 million for stock option exercises. During the six months ended June 30, 2022, the Company settled in cash $0.8 million for stock appreciation rights and received $0.3 million for stock option exercises.

	Three Months Ended June 30,					Six Months Ended June 30,
	2023			2022		2023			2022
	(in thousands)
Stock-based compensation - equity awards	$	706		$	615	$	1,381		$	1,019
Stock-based compensation - liability awards		(101	)		227		(127	)		1,245
Total stock-based compensation	$	605		$	842	$	1,254		$	2,264

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Stock options and performance shares

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

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.

In June 2023, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 334,753 shares at an exercise price of $4.19 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 $4.82 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 $5.54 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 $6.37 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.

During the six months ended June 30, 2023 and 2022, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo. 

	Six Months Ended June 30,
	2023			2022
Weighted average exercise price - ($/share)	$	4.19		$	6.41
Expected life in years		6.4			6.0
Average expected volatility		68	%		72	%
Risk-free interest rate		3.73	%		1.98	%
Expected dividend yield		5.97	%		2.30	%
Weighted average grant date fair value - ($/share)	$	2.29		$	2.84

Stock option activity associated with performance options for the six months ended June 30, 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		$	3.95
Granted		335			4.19
Exercised		(74	)		(1.68	)
Unvested shares forfeited		—			—
Vested shares expired		—			—
Outstanding at June 30, 2023		705		$	4.30			8.95	$	280
Exercisable at June 30, 2023		211		$	3.34			7.70	$	262

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Stock option activity associated with plain vanilla options for the six months ended June 30, 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		(164	)		(1.56	)
Unvested shares forfeited		—			—
Vested shares expired		—			—
Outstanding at June 30, 2023		223		$	2.07			0.73	$	376
Exercisable at June 30, 2023		223		$	2.07			0.73	$	376

As a result of tax withholding on options exercised, 44,655 shares were added to treasury during the six months ended June 30, 2023.

Restricted shares

Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three-year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant). The vesting of 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 six months ended June 30, 2023:

	Restricted Stock			Weighted Average Grant Date Fair Value
	(in thousands)
Non-vested shares outstanding at January 1, 2023		665		$	4.59
Awards granted		797			4.19
Awards vested		(354	)		3.92
Awards forfeited		(12	)		5.73
Non-vested shares outstanding at June 30, 2023		1,096		$	4.51

During the six months ended June 30, 2023, 81,342 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. 

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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, 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 RSU activity for the six months ended June 30, 2023:

	Restricted Stock			Weighted Average Conversion Date Fair Value
	(in thousands)
Non-vested shares outstanding at January 1, 2023		383		$	4.27
Awards granted		183			4.19
Awards vested		(259	)		4.27
Awards forfeited		(23	)		4.27
Non-vested shares outstanding at June 30, 2023		284		$	4.22

During the six months ended June 30, 2023, 162,328 shares were added to treasury because of tax withholding on the vesting of RSU’s.

PSUs are like 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 six months ended June 30, 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		(514	)		4.27
Awards forfeited		(36	)		4.27
Non-vested shares outstanding at June 30, 2023		140		$	4.27

During the six months ended June 30, 2023, 147,862 shares were added to treasury as a result of tax withholding on the vesting of PSU’s.

DSUs are like 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 the Company'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 June 30, 2023, approximately 101,313 DSUs are vested but not converted. During the second quarter of 2023, 358,563 DSUs were converted to shares of common stock of the company following the departure of Mr. David Cook and Mr. Timothy Marchant from the board of directors, of which 65,582 shares were forfeited back to VAALCO to satisfy applicable tax withholding obligations.

Stock appreciation rights (“SARs”)

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

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During the six months ended June 30, 2023, the Company did not grant SARs to employees or directors.

SAR activity for the six months ended June 30, 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 June 30, 2023		139		$	2.33		0.64	$	198
Exercisable at June 30, 2023		139		$	2.33		0.64	$	198

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 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.

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 that include Canada, Egypt, Equatorial Guinea and Gabon.

Income taxes attributable to continuing operations for the three and six months ended June 30, 2023 and 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:

	Three Months Ended June 30,					Six Months Ended June 30,
	2023			2022		2023		2022
U.S. Federal:	(in thousands)
Current	$	—		$	—	$	—	$	—
Deferred		871			2,617		1,457		(9,869	)
Foreign:
Current		12,401			20,402		24,701		26,093
Deferred		(1,684	)		23,233		201		25,400
Total	$	11,588		$	46,252	$	26,359	$	41,624

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The Company’s effective tax rate for the three and six months ended  June 30, 2023, excluding the impact of discrete items, was 68.42% and 63.32%. For the three and six months ended June 30, 2022, the effective tax rates were 73.37% and 72.59%. The total tax expense for the three months ended June 30, 2023, includes a discrete amount of ($0.5) million primarily related to adjustments made because of changes to oil price (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, i.e., oil price adjustment). For the six months ended June 30, 2023, the current tax expense of $24.7  million includes a $2.7 million unfavorable oil price adjustment. After excluding that impact, current income taxes were an expense of $22.0 million for the period. For the three months ended June 30, 2022, the current tax expense of $20.4 million includes a $1.2 million unfavorable oil price adjustment. After excluding this impact, current income taxes were $19.2 million for the period. For the six months ended June 30, 2022, the Company’s overall effective tax rate was appreciably impacted by non-deductible items associated with operations (which includes losses on derivative instruments) and the release of valuation allowance attributable to the current period. The total tax expense for the six months ended June 30, 2022 includes a discrete adjustment for the release of an additional $12.7 million of valuation allowance as a result of an increase in forecasted future earnings. For the six months ended June 30, 2022, the current tax expense of $26.1 million includes a $4.3 million unfavorable oil price adjustment. After excluding the impact, current income taxes were $21.8 million for the period.

As of June 30, 2023, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.

17. OTHER COMPREHENSIVE INCOME 

The Company’s other comprehensive income was $2.0 million for the three months ended June 30, 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
Accumulated other comprehensive income (loss) before reclassifications		2,006
Balance at June 30, 2023	$	3,060

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this 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:

● 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;

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● 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.

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, 2022 (“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 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, natural gas and NGLs. As operator, we have production operations and conduct exploration activities in Gabon, West 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 Financial Statements, we have discontinued operations associated with our activities in Angola, West Africa and Yemen.

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RECENT DEVELOPMENTS

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. On May 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share, which was paid on June 23, 2023 to stockholders of record at the close of business on May 24, 2023. On August 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on September 22, 2023 to stockholders of record at the close of business on August 25, 2023. 

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, 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 up to 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 several 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 CAD $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 $75.0  million and $1.7  million of “Net income” in the condensed consolidated statements of operations and comprehensive income for the six months ended June 30, 2023. For the three months ended June 30, 2023 the actual impact of the Arrangement Agreement was an increase to “Crude oil, natural gas and NGLs sales” of $31.3  million and $(8.0)  million of "Net Loss".

Entry into a Facility Agreement

On May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”), a wholly owned subsidiary of 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 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.

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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 next drilling campaign at Etame that is expected to occur in 2024. In October 2022, VAALCO successfully completed its transition to a Floating Storage and Offloading vessel (“FSO”) and related field reconfiguration processes. This project provides a low cost FSO solution that increases the storage capacity for the Etame block. The Company will continue to focus on operational excellence, including production uptime and enhancement in 2023 to minimize decline until the next drilling campaign.

The cost of the 2021/2022 drilling program with four wells and two workovers was $180 million, or $114 million, net to VAALCO’s participating interest.

At the end of June 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 six months ended June 30, 2023. Gas lift compression and subsea wells remained online with a high level of reliability through the six months ended June 30, 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. Continued optimization and understanding of the post reconfiguration process dynamics of the Etame platform, have maintained a very high uptime availability of Etame Facility and in turn the complete Etame field during the second quarter. Combining this with individual well and facility chemical injection optimization and facility pipeline pigging adjustments both on frequency of pigging and flow path targeting, has increased production through decrease in pipeline internal buildup and resulting back pressure, this in turn has provided more stable operations resulting in lower downtime. Through the second quarter of 2023 this continues to be a focus with positive results in production rates and uptime. Trials of new chemicals continue, for ensuring cost and production effectiveness of the Etame field operations.

Preventative maintenance activities returned to levels prior to the field reconfiguration, as the focus came back to steady state operation following project completion. Equipment Reliability and Availability remain at high levels. The actual percentages of Corrective Maintenance performed versus Preventative Maintenance performed remain well within VAALCO and Industry Best Practice standards.

Egypt 

We continued to use the EDC-64 rig in the Eastern Desert drilling campaign. We completed six wells in the second quarter of 2023, four development wells HE-4, HE-3, Arta 82 Red-Bed, and Arta-84 Nukhul, one injector well HE-5inj and one exploration well NWG-5C-1. Drilling an average of 2 wells per month we are drilling up our firm 2023 work program faster and at less cost.

The HE-4 development 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 464 bopd (field estimate) at 8% water cut.

The HE-5inj well achieved primary its objective by drilling the same producing reservoir as in HE-1X and/or HE-2X. The well spudded on April 16, 2023 and the rig was released on May 4, 2023. The recorded pressure data indicates the reservoir pressure in the well is depleted from the original pressure which gave an indication of the communication with the current producing wells. The well is completed as a water injector to support the producing reservoir at HE-1X and or HE-2X.

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The HE-3 development well was proposed as vertical development well to produce from the ASL-B2 sand as the primary target. The well spudded on May 10, 2023 and reached TD on May 17, 2023 at depth of 1,675 meters MD within Safra-sand. Open hole log evaluation indicated 3.0 meters of net pay across the ASL-B1 and ASL-B2 reservoirs. The well was perforated in both ASL-B2 sand units from 1,549 to 1,551 and 1,566.5 to 1,569.5 meters MD and was put on production. Current production is approximately 238 Bopd (field estimate) at 10% water cut.

The Arta-82 development well was spudded on May 25, 2023 and achieved its primary objective of the Red-Bed reservoir in a favorable position as per the prognosis. The well encountered a total of 42 feet of net pay. Current production is approximately 134 Bopd (field estimate) at 30% water cut.

The Arta-84 development well was spudded on June 6, 2023 and achieved its primary objective of the Nukhul reservoir. The well encountered a total of 34 feet of net pay in the Nukhul/Nukhul Marker reservoir. The well was cased and perforated from 3,462 to 3,495 feet. The reservoir requires a frac to produce and this is scheduled during the current frac campaign of 4 wells.

The NWG-5C1 exploration well was spudded on June 16, 2023 targeting the Nukhul Reservoir. The well reached TD in the Thebes formation on June 20, 2023. The mud log did not record any gas or oil shows in the Nukhul. No net pay was calculated on the petrophysical analysis of the Nukhul /Nukhul Marker reservoir. Based on this information, TransGlobe recommended to abandon the NWG-5C1 wellbore.

The SGZ-6X well in the South Ghazalat concession in the Western Desert was recompleted in the Upper Bahariya zone. After re-entry, recompletion and re-perforation in May 2023 the well only produced water with trace oil and gas. Production was suspended and the well secured while TransGlobe evaluate how to further appraise the concession. A forward work program is required to retain this acreage in the Western Desert.

Canada 

Early in 2023, two wells, the 1Q100/04-10-29-03W5 and the 4-19-29-3W5, were tied in. 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 and tied in and equipped in April and early May. 12-12-30-4W5 was put online in late April, and 16-30-29-3W5 was put online in early May with cycle times that were significantly less than historical cycle times. The wells flowed in the months of May and June. In early July the pump and rods were run on both wells. Both wells continue to produce and are exceeding expectations

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 June 30, 2023, production operations in the Etame Marin block included fifteen platform wells, plus 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 at the Etame platform. From the Etame platform, the crude oil is pumped through a riser system to the FSO where it is stored and ultimately offloaded. The leased FSO is anchored to the seabed on the block. The Etame field currently has a combined total of seventeen producing wells. During the three months ended June 30, 2023 and 2022, production from the block was 1,588 MBbls (812MBbls, net) and 1,638 MBbls (838 MBbls, net), respectively, as discussed below in “Results of Operations”. During the six months ended June 30, 2022 and 2023, production from the Etame Marin block was 3,055 MBbls (1,563 MBbls net) and 3,190 MBbls (1,632 MBbls net), respectively. 

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Egypt

In Egypt, 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 in both PSCs. During the three months ended June 30, 2023, production from the Eastern Desert was 1,054 MBbls (726 MBbls, net) as discussed below in “Results of Operations”. During the six months ended June 30, 2023, production from the Eastern Desert was 1,957 MBbls (1,342 MBbls, net). 

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 2,600 meters. All gas is delivered to a third party non-operated gas plant for processing. During the three months ended June 30, 2023, production from our Canadian assets was 275 MBoe to our working interest (253 MBoe, net) as discussed below in “Results of Operations”. During the six months ended June 30, 2023, production from our Canadian assets was 514 MBoe to our working interest (464 MBoe, net).

Equatorial Guinea

As of June 30, 2023, we had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. In February of 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 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 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 some minor changes required by the Joint Operating Agreement that require final ratification by the joint 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 for the area associated with the Venus development. The PSC also includes the portions of Block P not associated with the Block P - Venus development.

DISCONTINUED 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 and six months ended June 30, 2023 and 2022, the Angola segment did not have a material impact on 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 are presented in cash flows from discontinued operating activities for all periods presented in our consolidated statements of cash flows. For the three and six months ended June 30, 2023 and 2022, the Yemen segment did not have a material impact on our financial position, results of operations, cash flows and related disclosures.

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CAPITAL RESOURCES AND LIQUIDITY

Cash Flows 

Our cash flows for the six months ended June 30, 2023 and 2022 are as follows:

	Six Months Ended June 30,
	2023			2022			Increase (Decrease) in 2023 over 2022
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	77,013		$	67,041		$	9,972
Net change in operating assets and liabilities		571			2,004			(1,433	)
Net cash provided by (used in) continuing operating activities		77,584			69,045			8,539
Net cash used in discontinued operating activities		(15	)		(38	)		23
Net cash provided by (used in) operating activities		77,569			69,007			8,562
Net cash provided by (used in) investing activities		(54,832	)		(60,278	)		5,446
Net cash provided by (used in) in financing activities		(27,882	)		(5,922	)		(21,960	)
Effects of exchange rate changes on cash		(285	)		—			(285	)
Net change in cash, cash equivalents and restricted cash	$	(5,430	)	$	2,807		$	(8,237	)

The $10.0 million increase in net cash provided by operating activities before changes in operating assets and liabilities was due to a $49.6 million increase in depreciation expense and $33.5 million lower cash settlements on derivative contracts partially offset by a prior year $41.4 million derivative gain and a $13.9 million decrease in deferred tax expense. The net decrease in changes provided by operating assets and liabilities of $1.4 million for the six months ended June 30, 2023 compared to the same period of 2022 was primarily related to positive changes in trade receivable, receivables accounts with joint venture owners, other long-term assets and crude oil inventory (collectively $61.5 million). More than offsetting these changes were negative changes in other receivables, prepayments and other, accounts payable, foreign taxes payable, deferred taxes, and accrued liabilities and other (collectively negative $62.8 million).

The $5.5 million decrease in net cash used in investing activities during the six months ended June 30, 2023 was due to capital spending costs associated with the development drilling programs in Egypt and Canada not exceeding prior period expenditures along with reduced current year expenditures for Gabon. For the six months ended June 30, 2022, cash used in investing activities was due to increases in capital spending in 2022 for the Etame 8-H well, the Avouma 3H-ST well, ETBSM 1HB-ST well, the Etame field reconfiguration and other items to support the 2021/2022 drilling campaign.

Net cash used in financing activities during the six months ended June 30, 2023 included $13.5 million for dividend distributions, $11.4 million for treasury stock repurchases made under our stock repurchase plan as discussed in Note 10 to our financial statements or as a result of tax withholding on options exercised and on vested restricted stock as discussed in Note 15 to our financial statements, and $3.4 million of principal payments on our finance leases partially offset by $0.4 million in proceeds from options exercised. For the six months ended June 30, 2022, cash used in financing activities included $3.9 million for dividend distributions, $0.8 million for treasury stock repurchases, as a result of tax withholding on options exercised and vested restricted stock, $1.5 million of costs capitalized associated with our credit facility and $0.1 million of principal payments on our finance leases partially offset by $0.3 million in proceeds from options exercised.

Capital Expenditures 

For the six months ended June 30, 2023 we had accrual basis capital expenditures attributable to continuing operations of $41.9  million compared to $69.9  million accrual basis capital expenditures for the same period in 2022. For the six months ended June 30, 2023, our cash spending primarily 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, Etame field reconfigurations and FSO projects.

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

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Regulatory and Joint Interest Audits

We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements. See Note 10 to the 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. 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 statements of operations and comprehensive income. We record such derivative instruments as assets or liabilities in the unaudited condensed consolidated balance sheet. 

See the table below for the unexpired contracts at June 30, 2023:

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

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

Subsequent Event

On July 13, 2023, we entered into additional derivatives contracts for the fourth 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)
October 2023 - December 2023	Collars	Dated Brent		85,000	$	65.00	$	90.00

Cash on Hand

At June 30, 2023, we had unrestricted cash of $46.2 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.

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We currently sell all our crude oil production from Gabon under a 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 six months ended June 30, 2023, sales to Egypt were split between Mercuria and the EGPC. Mercuria purchased oil in January, while the EGPC performed May and June liftings. 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. For the three and six months ended June 30, 2023, revenues in Canada were concentrated in three separate customers. These customers were Plains Midstream (50.9%), AltaGas (19.1%), and PetroGas Energy (18.6%). 

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.

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 the FSO charter, 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 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.

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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 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. At September 30, 2022, our borrowing base was $50.0 million. The amount we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. We were in compliance with all debt covenants at June 30, 2023. As of June 30, 2023, we 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”).

Cash Requirements

Our material cash requirements generally consist of finance leases, operating leases, purchase obligations, capital projects and 3D seismic processing, the 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.

Abandonment Funding – Under the terms of the Etame PSC, we have 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 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 to VAALCO) on an undiscounted basis. The new abandonment estimate has been presented to the Gabonese Directorate of Hydrocarbons as required by the PSC. At June 30, 2023, the balance of the abandonment fund was $10.7 million ($6.3 million, net to VAALCO) on an undiscounted 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 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.

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Leases – We are a party to several operating and financing lease arrangements, including operating leases for the corporate office, a drilling rig, rental of marine vessels and helicopters, warehouse and storage facilities, equipment and financing lease agreements for the FSO and generators used in the operations of the 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 the 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 agreed to substitute the February 1, 2023 payment and issue a $10.0 million credit against receivables owed from EGPC. We will 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 June 30, 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 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.

On October 19, 2022, we issued final acceptance certificate of the FSO. On December 4, 2022, the first lifting from the FSO was successfully completed at the 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 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 Programs – In Egypt, we continued to use the EDC-64 rig in the Eastern Desert drilling campaign. We completed six wells in the second quarter of 2023, four development wells HE-4, HE-3, Arta 82 Red-Bed, and Arta-84 Nukhul, one injector well HE-5inj and one exploration well NWG-5C-1. We are drilling an average of 2 wells per month and we are drilling up our firm 2023 work program faster and at less cost.

The HE-4 development well was drilled to a total depth of 1,850 meters 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^th , 2023. Current production is approximately 464 Bopd (field estimate) at 8% water cut.

The HE-5inj well achieved primary its objective by drilling the same producing reservoir as in HE-1X and/or HE-2X. The well spudded on April 16, 2023 and the rig was released on May 4, 2023. The recorded pressure data indicates the reservoir pressure in the well is depleted from the original pressure which gave an indication of the communication with the current producing wells. The well is completed as a water injector to support the producing reservoir at HE-1X and or HE-2X.

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The HE-3 development well was proposed as vertical development well to produce from the ASL-B2 sand as the primary target. The well spudded on May 10, 2023 and reached TD on May 17, 2023 at depth of 1,675 m MD within Safra-sand. Open hole log evaluation indicated 3.0 meters of net pay across the ASL-B1 and ASL-B2 reservoirs. The well was perforated in both ASL-B2 sand units from 1,549 to 1,551 and 1,566.5 to 1,569.5 meters MD and was put on production. Current production is approximately 238 Bopd (field estimate) at 10% water cut.

The Arta-82 development well was spudded on May 25, 2023 and achieved its primary objective of the Red-Bed reservoir in a favorable position as per the prognosis. The well encountered total of 42 feet of net pay. Current production is approximately 134 Bopd (field estimate) at 30% water cut.

The Arta-84 development well was spudded on June 6, 2023 and achieved its primary objective of the Nukhul reservoir. The well encountered total of 34 feet of net pay in the Nukhul/Nukhul Marker reservoir. The well was cased and perforated from 3,462 – 3,495 ft. The reservoir requires a frac to produce and this is scheduled during the current frac campaign of 4 wells.

The NWG-5C1 exploration well was spudded on June 16, 2023 targeting the Nukhul Reservoir. The well reached TD in the Thebes formation on June 20, 2023. The mud log did not record any gas or oil shows in the Nukhul. No net pay was calculated on the petrophysical analysis of the Nukhul /Nukhul Marker reservoir. Based on this information, the Company recommended to abandon the NWG-5C1 wellbore.

The SGZ-6X well in the South Ghazalat concession in the Western Desert was recompleted in the Upper Bahariya zone. After re-entry, recompletion and re-perforation, in May 2023 the well only produced water with trace oil and gas. Production was suspended and the well secured while TransGlobe evaluate how to further appraise the concession. A forward work program is required to retain this acreage in the Western Desert.

In Canada, early in 2023, two wells, the 1Q100/04-10-29-03W5 and the 4-19-29-3W5, were tied in. 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 a total depth of 4,403 meters. The 2 wells were completed between late March and early April and tied in and equipped in April and early May. 12-12-30-4W5 was put online in late April, and 16-30-29-3W5 was put online in early May with cycle times that were significantly less than historical cycle times. The wells flowed in the months of May and June. In early July, the pump and rods were run on both wells. Both wells continue to produce and are exceeding expectations.

TransGlobe Acquistion – On October 13, 2022, VAALCO and AcquireCo completed the business combination with TransGlobe. At the effective time of the Arrangement and pursuant to the Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement was converted into the right to 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 addition, we incurred $14.6 million of transaction costs associated with the acquisition agreement. Please refer to Note 3 to our Financial Statements for additional information regarding the Arrangement.

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. On May 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share, which was paid on June 23, 2023 to stockholders of record at the close of business on May 24, 2023. On August 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on September 22, 2023 to stockholders of record at the close of business on August 25, 2023. 

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.

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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 up to 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 June 30, 2023, approximately $17.5  million remained available for repurchase under current authorizations.

Trends and Uncertainties

Geopolitical Climate and Other Market Forces – 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 and natural gas markets. The ongoing conflict has caused, and could intensify, volatility in oil and natural gas prices, and the extent and duration of the military action, sanctions and resulting market disruptions could 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 the Chinese economy is negatively impacting the global market and the global supply chain problems may have a material adverse impact on our financial results and business operations, including our timing and ability to complete future drilling campaigns and other efforts required to advance the development of our crude oil, natural gas and NGLs properties.

Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and 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, 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 per day through December 2023 by various members in addition to the 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 8 MBbls per day. On June 5, 2023, OPEC meeting Saudia Arabia agreed to an additional 1 MMBbls per day for July 2023 but could be extended. In addition, members of OPEC+ agreed to extend the group's existing supply cuts of 3.7 MMBbls per day for another year (December 2024). The Company has not received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiatives. 

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 (“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 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.

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COVID-19 Pandemic – On May 5, 2023, the head of the UN World Health Organization (WHO) declared “with great hope” an end to COVID-19 as a public health emergency, stressing that it does not mean the disease is no longer a global threat.

Hedging

We seek to mitigate the impact of volatility in crude oil prices through hedging. See the table below for the unexpired contracts entered into prior to June 30, 2023:

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

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 July 13, 2023, we entered into additional derivatives contracts for the fourth 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)
October 2023 - December 2023	Collars	Dated Brent		85,000	$	65.00	$	90.00

CRITICAL ACCOUNTING POLICIES

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

NEW ACCOUNTING STANDARDS

See Note 2 to the Financial Statements.

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RESULTS OF OPERATIONS 

Three Months Ended June 30, 2023 Compared to the Three Months Ended June 30, 2022

Net income for the three months ended June 30, 2023 was $6.8 million compared to net income of $15.1 million for the same period of 2022. See discussion below for changes in revenue and expense.

Crude oil, natural gas and NGL revenues decreased  $1.7 million, or approximately 2%, to $109.2 million during the three months ended June 30, 2023 from $ 111.0  million for the same period in the prior year. The revenue decrease is attributable to significantly higher realized sales prices during the prior period, which was partially offset by higher volumes sold in Gabon and the addition of the Egypt and Canada segments acquired in the Arrangement with TransGlobe.

	Three Months Ended June 30,
	2023			2022		Increase/(Decrease)
	(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		1,803			958		845
Average crude oil sales price (per Bbl)	$	59.37		$	113.38	$	(54.01	)
Net crude oil, natural gas, and NGLs revenue	$	109,240		$	110,985	$	(1,745	)
Operating costs and expenses:
Production expense		38,604			25,475		13,129
FPSO demobilization		5,647			—		5,647
Exploration expense		57			67		(10	)
Depreciation, depletion and amortization		38,003			8,191		29,812
General and administrative expense		5,395			3,534		1,861
Credit losses and other		680			571		109
Total operating costs and expenses		88,386			37,838		50,548
Other operating expense, net		(303	)		-		(303	)
Operating income	$	20,551		$	73,147	$	(52,596	)

The revenue changes in the three months ended June 30, 2023 compared to the same period in  2022 identified as related to changes in price or volume, are shown in the table below:

(in thousands)
Price	$	(97,362	)
Volume		95,772
Other		(155	)
	$	(1,745	)

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

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

	Three Months Ended June 30,
	2023		2022
Net crude oil production (MBbls)		1,791		838
Net crude oil sales (MBbls)		1,803		958
Average realized crude oil price ($/Bbl)	$	59.37	$	113.38
Average Dated Brent spot price* ($/Bbl)		77.99		113.84

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

Crude oil, natural gas and NGL revenues decreased  $1.7 million, or approximately 2%, during the three months ended June 30, 2023 compared to the same period of 2022. 

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Gabon

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $ 77.9  million of revenue to the Company’s total revenue during the three months ended June 30, 2023. This compares to the $ 111.0  million of revenue contributed by the Segment during the three months ended June 30, 2022. The total barrels lifted in Gabon for the three months ended June 30 was slightly higher than the three months ended June  2022, mainly due to the additional production from the completed 2021/2022 drilling campaign. This was more than offset by the Gabon per barrel price received during the three months ended June 30, 2023 which was $35.14 less than the price received in 2022. Our share of crude oil inventory, excluding royalty barrels, was approximately 227,556 and 45,794 barrels at June 30, 2023 and 2022, respectively.

Egypt

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 June 30, 2023, all the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contribute d $21.3  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 206,136 barrels at June 30, 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 June 30, 2022.

Canada

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $ 10.0  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 June 30, 2022.

Production expenses increased $13.1 million, or approximately 52%, for the three months ended June 30, 2023 to $38.6 million from $25.5  million for the same period in the prior year. The increase in production expense was primarily driven by increased production and costs associated with the TransGlobe combination as well as higher Gabon costs due to the completed 2021/2022 drilling campaign. VAALCO has seen inflationary pressure on personnel and contractor costs. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended June 30, 2023 decreased to $ 21.51 per ba rrel from $26.58 per barrel for the three months ended June 30, 2022 primarily as a result of higher sales volumes for the current period. For both the three months ended June 30, 2023 and 2022, respectively, we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic. For the three months ended June 30, 2023 the costs associated with proactive measures related to COVID were not material. For the three months ended June 30, 2022, we incurred $0.5 million in additional costs related to the proactive measures taken in response to the pandemic.

FPSO Demobilization - Norms Waste Disposal for the three months ended June 30, 2023 was $5.6 million. In the second quarter of 2023, it was determined that there was more waste than anticipated connected to the FPSO from VAALCO's usage. As such, VAALCO incurred an additional $5.6 million in decommissioning fees, which was reported as a separate line item on the income statement. No similar expense was recorded for the three months ended June 30, 2022. 

Exploration expense for the three months ended June 30, 2023 and 2022 was not material to our results.

Depreciation, depletion and amortization costs increased $29.8 million, or approximately 364% for the three months ended June 30, 2023 to $38.0 million from $8.2  million for the same period in the prior year. The increase in depreciation, depletion and amortization expense for the three months ended June 30, 2023 compared to thee months ended June 30, 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 acquired TransGlobe assets. In addition, new wells were brought online in 2023 for both Egypt and Canada, which also increased depreciation, depletion and amortization expense

General and administrative expenses increased $1.9 million, or 53% for the three months ended June 30, 2023 to $5.4 million from $3.5  million for the same period in the prior year. The increase in general and administrative expenses is primarily due to higher corporate G&A associated with TransGlobe salaries and wages expense for the three months ended June 30, 2023 compared to the same period in 2022.

Credit losses and other increased by $0.1 million to $0.7 million for the three months ended June 30, 2023 from $0.6  million for the three months ended June 30, 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. For the three months ended June 30, 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.

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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 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 have 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 June 30, 2023 we added $0.5 million to the allowance account for the current quarter's 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 Financial Statements.

Other operating expense, net for each of the three months ended June 30, 2023 and  2022 was not material to our results.

Derivative instruments gain (loss), net is attributable to our swaps and collars as discussed in Note 8 to the Financial Statements. Derivative gain (loss) decreased by $9.6 million, or approximately 100% to an immaterial gain for the three months ended June 30, 2023 from a loss of  $9.6 million during the same period in the prior year. Derivative gains (losses) for the three months ended June 30, 2022 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the three months ended June 30, 2022. Our derivative instruments currently cover a portion of our production through December 2023. 

Interest expense, net was $1.7 million for the three months ended June 30, 2023 compared to an expense of  $0.1  million during the same period in 2022. The increase of net interest expense for the three months ended June 30, 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 decreased by $1.6 million to expense of $0.5 million for the three months ended June 30, 2023 from an expense of $2.1  million for the three months ended June 30, 2022 . Other (expense) income, net normally consists of foreign currency gains and losses as discussed in Note 1 to the F inancial Statements. Foreign currency losses are the primary driver for the activity during the three months ended June 30, 2022 along with $1.2 million of transactions costs associated with the Arrangement with TransGlobe.
 

Income tax expense (benefit) for the three months ended June 30, 2023 was an expense of $ 11.6  million. This is comprised of current tax expense of $ 12.4  million and $ (0.8)  million of deferred tax benefit. Income tax expense (benefit) for the three months ended June 30, 2022 was an expense of $ 46.3  million. This is comprised of current tax expense of $ 20.4  million and $ 25.9  million of deferred tax expense. 

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Six Months Ended June 30, 2023 Compared to the Six Months Ended June 30, 2022

Net income for the six months ended June 30, 2023 was $10.2 million compared to net income of $27.3 million for the same period of 2022. See discussion below for changes in revenue and expense.

Crude oil, natural gas and NGLs revenues increased $10.0 million, or approximately 6%, to $189.6 million during the six months ended June 30, 2023 from $179.6 million for the same period in the prior year. The revenue increase 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. 

	Six Months Ended June 30,
	2023			2022			Increase/(Decrease)
	(in thousands except per Boe information)
Net crude oil, natural gas, and NGLs sales volume (MBoe)		3,027			1,574			1,453
Average crude oil, natural gas and NGLs sales price (per Boe)	$	61.92		$	111.92		$	(50.00	)
Net crude oil, natural gas, and NGLs revenue	$	189,643		$	179,641		$	10,002
Operating costs and expenses:
Production expense		66,804			43,835			22,969
FPSO demobilization - Norms waste disposal		5,647			—			5,647
Exploration expense		65			194			(129	)
Depreciation, depletion and amortization		62,420			12,864			49,556
General and administrative expense		10,619			8,528			2,091
Credit losses and other		1,615			1,063			552
Total operating costs and expenses		147,170			66,484			80,686
Other operating expense, net		(303	)		(5	)		(298	)
Operating income	$	42,170		$	113,152		$	(70,982	)

The revenue changes in the six months ended June 30, 2023 compared to the same period in 2022 identified as related to changes in price or volume, are shown in the table below: 

(in thousands)
Price	$	(151,340	)
Volume		162,609
Other		(1,267	)
	$	10,002

(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.

	Six Months Ended June 30,
	2023		2022
Net crude oil, natural gas and NGLs production (MBoe)		3,438		1,563
Net crude oil, natural gas and NGLs sales (MBoe)		3,027		1,574
Average realized crude oil, natural gas and NGLs price ($/Boe)	$	61.92	$	111.92
Average Dated Brent spot price* ($/Bbl)	$	79.58	$	107.59

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

Crude oil, natural gas and NGL revenues increased $10.0 million, or approximately 6%, during the six months ended June 30, 2023 compared to the same period of 2022. 

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Gabon

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $114.7  million of revenue to the Company’s total revenue during the six months ended June 30, 2023. This compares to the $179.6  million of revenue contributed by the Segment during the six months ended June 30, 2022. The total barrels lifted in Gabon for the six months ended June 30 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 six months ended June 30, 2023 was $33.14 less than the price received in 2022. Our share of crude oil inventory, excluding royalty barrels, was approximately 227,566 and 45,794 barrels at June 30, 2023 and 2022, respectively.

Egypt

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 six months ended June 30, 2023, the oil sold in Egypt was through third party sales to Mercuria Energy during the first quarter, and through direct sales to EGPC during the second quarter. The Company’s Egypt segment contributed $56.0  million of revenue to the Company’s total revenue for the six months ended June 30, 2023. At the end of the quarter, the Company’s Egypt segment had approximately 206,136 barrels at June 30, 2023 in oil inventory. Since the Company acquired its Egyptian segment in the fourth quarter of 2022, there are no comparable revenues for the six months ended June 30, 2022.

Canada

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $18.9  million of revenue to the Company’s total revenue for the six months ended June 30, 2023. Since the Company acquired its Canadian segment in the fourth quarter of 2022, there are no comparable revenues for the six months ended June 30, 2022.

Production expenses increased $23.0 million, or approximately 52%, for the six months ended June 30, 2023 to $66.8 million from $43.8 million for the same period in the prior year. The increase in production expense was primarily driven by increased production and costs associated with the TransGlobe combination as well as higher Gabon costs due to the added production from the now completed 2021/2022 drilling campaign. VAALCO has seen inflationary pressure on personnel and contractor costs. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the six months ended June 30, 2023 decreased to $22.48 per barrel from $27.85 per barrel for the six months ended June 30, 2022 primarily as a result of higher sales volumes. For the six months ended June 30, 2023, we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic. For the six months ended June 30, 2023 the costs associated with proactive measures related to COVID were not material. For the six months ended June 30, 2022, we incurred $1.4 million in higher costs related to the proactive measures taken in response to the pandemic.

FPSO Demobilization - Norms Waste Disposal for the six months ended June 30, 2023 was $5.6 million. In the second quarter of 2023, it was determined that there was more waste than anticipated connected to the FPSO from VAALCO's usage. As such, VAALCO incurred an additional $5.6 million in decommissioning fees, which was reported as a separate line item on the income statement. No similar expense was recorded for the six months ended June 30, 2022. 

Exploration expense for the six months ended June 30, 2023 and 2022 was not material to our results.

Depreciation, depletion and amortization costs increased $49.6 million, or approximately 385% for the six months ended June 30, 2023 to $62.4 million from $12.9 million for the same period in the prior year. The increase in depreciation, depletion and amortization expense for the six months ended June 30, 2023 compared to six months ended June 30, 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. In addition, new wells were brought online in 2023 for both Egypt and Canada, which also increased depreciation, depletion and amortization expense

General and administrative expenses increased $2.1 million, or 25%, for the six months ended June 30, 2023 to $10.6 million from $8.5 million for the same period in the prior year. The increase in general and administrative expenses is primarily due to payroll expenses associated with TransGlobe's corporate segment for the six months ended June 30, 2023 compared to the same period in 2022.

Credit losses and other increased by $0.6 to $1.6 million for the six months ended June 30, 2023 from $1.1 million for the six months ended June 30, 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 six months ended June 30, 2023, we recognized an additional amount to the credit loss allowance of $0.5 million for crude oil delivered to the refinery during the six months. For the six months ended June 30, 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. 

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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 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 six months ended June 30, 2023 we added $1.1 million to the allowance account for the current year's 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 Financial Statements.

Other operating expense, net for each of the six months ended June 30, 2023 and 2022 was not material to our results.

Derivative instruments gain (loss), net is attributable to our swaps and collars as discussed in Note 8 to the Financial Statements. Derivative loss decreased by $41.4 million, or approximately 100% to an immaterial gain for the six months ended June 30, 2023 from a loss of $41.3 million during the same period in the prior year. Derivative gains (losses) for the six months ended June 30, 2022 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the six months ended June 30, 2022. During 2022, we changed the type of our derivative instruments from swaps to costless collars. Our derivative instruments currently cover a portion of our production through December 2023. 

Interest expense, net was $3.9 million for the six months ended June 30, 2023 compared to an expense of $0.1 million during the same period in 2022. The increase of net interest expense for the six months ended June 30, 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 decreased by $1.1 million to expense of $1.7 million for the six months ended June 30, 2023 from an expense of $2.8 million for the six months ended June 30, 2022. Other (expense) income, net normally consists of foreign currency gains and (losses) as discussed in Note 1 to the Financial Statements. However, the six months ended June 30, 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 the Financial Statements. For the six months ended June 30, 2022, foreign currency losses are the primary driver for the activity along with $1.2 million of transactions costs associated with the Arrangement with TransGlobe. There was also $1.5 million in foreign exchange activity for the six months ended June 30, 2022 compared to an immaterial amount for the same period in 2023. 

Income tax expense (benefit) for the six months ended June 30, 2023 was an expense of $26.4 million. This is comprised of current tax expense of $24.7  million and $1.7  million of deferred tax expense. Income tax expense (benefit) for the six months ended June 30, 2022 was an expense of $41.6 million. This is comprised of current tax expense of $26.1  million and $15.5  million of deferred tax expense.

64

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MARKET RISK

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

FOREIGN EXCHANGE RISK

Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of June 30, 2023, we had net monetary assets of $41.2 million (XAF 24,851.6 million) denominated in XAF. A 10% weakening of the CFA relative to the U.S. dollar would have a $3.7 million reduction in the value of these net assets. For the three and six months ended June 30, 2023, we had expenditures of approximately $12.8 million and $24.5 million, respectively, (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 six months ended June 30, 2023 by approximately $0.7 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 six months ended June 30, 2023 by approximately $0.8 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 June 30, 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 six months ended June 30, 2023 by $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 six months ended June 30, 2023 by $0.1 million.

COUNTERPARTY RISK

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

COMMODITY PRICE RISK

Our major market risk exposure continues to be the prices received for our crude oil and natural gas production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil and natural gas have been volatile and 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 968 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $4.8 million decrease per quarter in revenues and operating income (loss) and a $4.3 million decrease per quarter in net income (loss).

65

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 253 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $1.3 million decrease per quarter in revenues and operating income (loss) and a $1.0 million decrease per quarter in net income (loss).

As of June 30, 2023, we had unexpired derivative instruments outstanding covering approximately 287 MBbls of production through September 30, 2023. In July of 2023, we added derivative contracts covering 255 MBbls of production from October 2023 through December 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 the 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 June 30, 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.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

Notwithstanding the identified material weaknesses, management, including our principal executive officer and principal financial officer, believes the unaudited 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.

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.

66

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 June 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sale of Equity Securities

There were no sales of unregistered securities during the quarter ended June 30, 2023 that were not previously reported on a Current Report on Form 8-K.

Issuer Repurchases of Common Stock

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 up to 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 June 30, 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
April 1, 2023 - April 30, 2023		303,969	$	4.94		303,969	$	21,003,245
May 1, 2023 - May 31, 2023		362,843	$	4.14		362,843	$	19,502,740
June 1, 2023 - June 30, 2023		494,164	$	4.05		494,164	$	17,504,007
Total		1,160,976				1,160,976

See Note 14 to the Financial Statements for further discussion.

67

Subsequent to June 30, 2023 and through August 4, 2023, the following table represents the details of various repurchases under the Plan:

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
July 1, 2023 - July 31, 2023		505,720	$	3.96		505,720	$	15,504,180
August 1, 2023 - August 4, 2023		98,411	$	4.29		98,411	$	15,082,133
Total		604,131				604,131

 ITEM 5. OTHER INFORMATION

During the three months ended June 30, 2023, none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act)

68

ITEM 6. EXHIBITS

(a) Exhibits

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).
3.1.1	Certificate of Amendment to Restated 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 Current Report on Form 8-K filed on December 23, 2015, and incorporated herein by reference).
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a)	Inline XBRL Instance Document.
101.SCH(a)	Inline XBRL Taxonomy Schema Document.
101.CAL(a)	Inline XBRL Calculation Linkbase Document.
101.DEF(a)	Inline XBRL Definition Linkbase Document.
101.LAB(a)	Inline XBRL Label Linkbase Document.
101.PRE(a)	Inline XBRL Presentation Linkbase Document.
104	Cover Page Interactive Data File (Formatted as Inline XBRL and contained in Exhibit 101).

(a) Filed herewith

(b) Furnished herewith

* Management contract or compensatory plan or arrangement. 

69

SIGNATURE

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

VAALCO ENERGY, INC.

(Registrant)

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

Dated: August 9, 2023

70

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO

EXCHANGE ACT RULES 13a-14(a) AND 15d-14(a),

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, George W.M. Maxwell, certify that:

(1) I have reviewed this quarterly report on Form 10-Q of VAALCO Energy, Inc.;

(2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

(5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 9, 2023

/s/ George W.M. Maxwell

George W.M. Maxwell

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO

EXCHANGE ACT RULES 13a-14(a) AND 15d-14(a),

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Ronald Bain, certify that:

(1) I have reviewed this quarterly report on Form 10-Q of VAALCO Energy, Inc.;

(2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

(5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 9, 2023

/s/ Ronald Bain

Ronald Bain

Chief Financial Officer

(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of VAALCO Energy, Inc. (the “Company”) on Form 10-Q for the quarterly period ended June 30, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George W.M. Maxwell, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: August 9, 2023

/s/ George W.M. Maxell

George W.M. Maxwell, Chief Executive Officer

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of VAALCO Energy, Inc. (the “Company”) on Form 10-Q for the quarterly period ended June 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I,  Ronald Bain,  Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities and Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: August 9, 2023

/s/ Ronald Bain 

Ronald Bain,  Chief Financial Officer

(Principal Financial Officer)

XML

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2023	Aug. 04, 2023
Document Information [Line Items]
Entity Central Index Key	0000894627
Entity Registrant Name	VAALCO ENERGY INC /DE/
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2023
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2023
Document Transition Report	false
Entity File Number	1-32167
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	76-0274813
Entity Address, Address Line One	9800 Richmond Avenue
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77042
City Area Code	713
Local Phone Number	623-0801
Title of 12(b) Security	Common Stock
Trading Symbol	EGY
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		106,475,814

XML

Condensed Consolidated Balance Sheets (Current Period Unaudited) - USD ($) $ in Thousands	Jun. 30, 2023		Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 46,186		$ 37,205
Restricted cash	113		222
Receivables:
Trade, net	57,360		52,147
Accounts with joint venture owners, net of allowance for credit losses of $0.5 and $0.3 million, respectively	216		15,830
Foreign income taxes receivable	0		2,769
Other, net of allowance for credit losses of $3.5 and $0.0 million, respectively	66,615		68,519
Crude oil inventory	10,800		3,335
Prepayments and other	18,077		20,070
Total current assets	199,367		200,097
Crude oil and natural gas properties, equipment and other - successful efforts method, net	481,740		495,272
Other noncurrent assets:
Restricted cash	1,779		1,763
Value added tax and other receivables, net of allowance of $9.5 million and $8.4 million, respectively	8,807		7,150
Right of use operating lease assets	1,639		2,777
Right of use finance lease assets	90,584		90,698
Deferred tax assets	37,155		35,432
Abandonment funding	6,268		20,586
Other long-term assets	1,674		1,866
Total assets	829,013	[1]	855,641	[2]
Current liabilities:
Accrued liabilities and other	84,104		91,392
Operating lease liabilities - current portion	1,667		2,314
Finance lease liabilities - current portion	7,684		7,811
Foreign income taxes payable	12,575		0
Current liabilities - discontinued operations	673		687
Total current liabilities	153,703		162,090
Asset retirement obligations	42,958		41,695
Operating lease liabilities - net of current portion	130		686
Finance lease liabilities - net of current portion	79,856		78,248
Deferred tax liabilities	82,895		81,223
Other long-term liabilities	17,465		25,594
Total liabilities	377,007		389,536
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, $25 par value; 500,000 shares authorized, none issued	0		0
Common stock, $0.10 par value; 160,000,000 shares authorized, 121,205,919 and 119,482,680 shares issued, 106,997,933 and 107,852,857 shares outstanding, respectively	12,121		11,948
Additional paid-in capital	355,206		353,606
Accumulated other comprehensive income	3,060		1,179
Less treasury stock, 14,207,986 and 11,629,823 shares, respectively, at cost	(59,055)		(47,652)
Retained earnings	140,674		147,024
Total shareholders' equity	452,006		466,105
Total liabilities and shareholders' equity	829,013		855,641
Nonrelated Party [Member]
Current liabilities:
Accounts payable	40,716		59,886
Related Party [Member]
Current liabilities:
Accounts payable	$ 6,284		$ 0

[1] Includes assets acquired in the TransGlobe acquisition

[2] Includes assets acquired in the Sasol acquisition

XML

Condensed Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - USD ($) $ in Thousands	Jun. 30, 2023	Dec. 31, 2022
Allowance for accounts with joint ventures	$ 500	$ 300
Allowance for other receivables	3,500	0
Allowance for value added tax and other receivables	$ 9,500	$ 8,400
Preferred stock, par value (in dollars per share)	$ 25	$ 25
Preferred stock, shares authorized (in shares)	500,000	500,000
Preferred stock, shares issued (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.10	$ 0.10
Common stock, shares authorized (in shares)	160,000,000	160,000,000
Common stock, shares issued (in shares)	121,205,919	119,482,680
Common stock, shares outstanding (in shares)	106,997,933	107,852,857
Treasury stock, shares (in shares)	14,207,986	11,629,823

XML

Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Revenues:
Crude oil, natural gas and natural gas liquids sales	$ 109,240	$ 110,985	$ 189,643	$ 179,641
Operating costs and expenses:
Production expense	38,604	25,475	66,804	43,835
FPSO Demobilization - Norms Waste Disposal	5,647	0	5,647	0
Exploration expense	57	67	65	194
Depreciation, depletion and amortization	38,003	8,191	62,420	12,864
General and administrative expense	5,395	3,534	10,619	8,528
Credit losses and other	680	571	1,615	1,063
Total operating costs and expenses	88,386	37,838	147,170	66,484
Other operating expense, net	(303)	0	(303)	(5)
Operating income	20,551	73,147	42,170	113,152
Other income (expense):
Derivative instruments gain (loss), net	31	(9,542)	52	(41,300)
Interest expense, net	(1,703)	(118)	(3,949)	(121)
Other expense, net	(537)	(2,111)	(1,677)	(2,807)
Total other expense, net	(2,209)	(11,771)	(5,574)	(44,228)
Income from continuing operations before income taxes	18,342	61,376	36,596	68,924
Income tax expense (benefit)	11,588	46,252	26,359	41,624
Income from continuing operations	6,754	15,124	10,237	27,300
Loss from discontinued operations, net of tax	(2)	(20)	(15)	(32)
Net income	6,752	15,104	10,222	27,268
Other comprehensive income (loss)
Currency translation adjustments	2,006	0	1,881	0
Comprehensive income	$ 8,758	$ 15,104	$ 12,103	$ 27,268
Basic net income per share:
Income from continuing operations (in dollars per share)	$ 0.06	$ 0.25	$ 0.10	$ 0.46
Loss from discontinued operations, net of tax (in dollars per share)	0	0	0	0
Net income per share (in dollars per share)	$ 0.06	$ 0.25	$ 0.10	$ 0.46
Basic weighted average shares outstanding (in shares)	106,965	58,925	107,175	58,814
Diluted net income per share:
Income from continuing operations (in dollars per share)	$ 0.06	$ 0.25	$ 0.09	$ 0.45
Loss from discontinued operations, net of tax (in dollars per share)	0	0	0	0
Net income per share (in dollars per share)	$ 0.06	$ 0.25	$ 0.09	$ 0.45
Diluted weighted average shares outstanding (in shares)	107,613	59,361	108,050	59,278

XML

Condensed Consolidated Statements of Shareholders' Equity (Unaudited) - USD ($) $ in Thousands	Cumulative Effect, Period of Adoption, Adjustment [Member] Common Stock [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Treasury Stock, Common [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Additional Paid-in Capital [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] AOCI Attributable to Parent [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Retained Earnings [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member]	Common Stock [Member]	Treasury Stock, Common [Member]	Additional Paid-in Capital [Member]	AOCI Attributable to Parent [Member]	Retained Earnings [Member]	Total
Balance (in shares) at Dec. 31, 2021							69,562,000	(10,939,000)
Balance at Dec. 31, 2021							$ 6,956	$ (43,847)	$ 76,700		$ 104,488	$ 144,297
Shares issued - stock-based compensation (in shares)							300,000	(64,000)
Shares issued - stock-based compensation							$ 30	$ 0	168		0	198
Stock-based compensation expense							0	$ 0	404		0	404
Treasury stock (in shares)								0
Treasury stock							0	$ (387)	0		0	(387)
Dividend distributions											(1,929)	(1,929)
Net income							$ 0	$ 0	0		12,164	12,164
Balance (in shares) at Mar. 31, 2022							69,862,000	(11,003,000)
Balance at Mar. 31, 2022							$ 6,986	$ (44,234)	77,272		114,723	154,747
Balance (in shares) at Dec. 31, 2021							69,562,000	(10,939,000)
Balance at Dec. 31, 2021							$ 6,956	$ (43,847)	76,700		104,488	144,297
Net income												27,268
Balance (in shares) at Jun. 30, 2022							70,125,000	(11,057,000)
Balance at Jun. 30, 2022							$ 7,013	$ (44,635)	77,919		127,884	168,181
Balance (in shares) at Mar. 31, 2022							69,862,000	(11,003,000)
Balance at Mar. 31, 2022							$ 6,986	$ (44,234)	77,272		114,723	154,747
Shares issued - stock-based compensation (in shares)							263,000	(54,000)
Shares issued - stock-based compensation							$ 27	$ 0	31		0	58
Stock-based compensation expense							0	$ 0	616		0	616
Treasury stock (in shares)								0
Treasury stock							0	$ (401)	0		0	(401)
Dividend distributions											(1,943)	(1,943)
Net income							$ 0	$ 0	0		15,104	15,104
Balance (in shares) at Jun. 30, 2022							70,125,000	(11,057,000)
Balance at Jun. 30, 2022							$ 7,013	$ (44,635)	77,919		127,884	168,181
Balance (in shares) at Dec. 31, 2022							119,483,000	(11,630,000)
Balance (Accounting Standards Update 2016-13 [Member]) at Dec. 31, 2022	$ 0	$ 0	$ 0	$ 0	$ (3,120)	$ (3,120)
Balance at Dec. 31, 2022							$ 11,948	$ (47,652)	353,606	$ 1,179	147,024	466,105
Shares issued - stock-based compensation (in shares)							633,000	(187,000)
Shares issued - stock-based compensation							$ 64	$ 0	210	0	0	274
Stock-based compensation expense							$ 0	$ 0	683	0	0	683
Common shares purchased (in shares)							0	(981,000)
Common shares purchased							$ 0	$ (4,517)	0	0	0	(4,517)
Treasury stock (in shares)								0
Treasury stock							0	$ (860)	0	0	0	(860)
Dividend distributions											(6,735)	(6,735)
Other comprehensive loss							0	0	0	(125)	0	(125)
Net income							$ 0	$ 0	0	0	3,470	3,470
Balance (in shares) at Mar. 31, 2023							120,116,000	(12,798,000)
Balance at Mar. 31, 2023							$ 12,012	$ (53,029)	354,499	1,054	140,639	455,175
Balance (in shares) at Dec. 31, 2022							119,483,000	(11,630,000)
Balance (Accounting Standards Update 2016-13 [Member]) at Dec. 31, 2022	$ 0	$ 0	$ 0	$ 0	$ (3,120)	$ (3,120)
Balance at Dec. 31, 2022							$ 11,948	$ (47,652)	353,606	1,179	147,024	466,105
Net income												10,222
Balance (in shares) at Jun. 30, 2023							121,206,000	(14,208,000)
Balance at Jun. 30, 2023							$ 12,121	$ (59,055)	355,206	3,060	140,674	452,006
Balance (in shares) at Mar. 31, 2023							120,116,000	(12,798,000)
Balance at Mar. 31, 2023							$ 12,012	$ (53,029)	354,499	1,054	140,639	455,175
Shares issued - stock-based compensation (in shares)							1,090,000	(249,000)
Shares issued - stock-based compensation							$ 109	$ 0	(1)	0	0	108
Stock-based compensation expense							$ 0	$ 0	708	0	0	708
Common shares purchased (in shares)							0	(1,161,000)
Common shares purchased							$ 0	$ (5,023)	0	0	0	$ (5,023)
Treasury stock (in shares)							0	0				(1,160,976)
Treasury stock							$ 0	$ (1,003)	0	0	0	$ (1,003)
Dividend distributions											(6,717)	(6,717)
Other comprehensive loss							0	0	0	2,006	0	2,006
Net income							$ 0	$ 0	0	0	6,752	6,752
Balance (in shares) at Jun. 30, 2023							121,206,000	(14,208,000)
Balance at Jun. 30, 2023							$ 12,121	$ (59,055)	$ 355,206	$ 3,060	$ 140,674	$ 452,006

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 6,752	$ 3,470	$ 15,104	$ 12,164	$ 10,222	$ 27,268
Adjustments to reconcile net income to net cash provided by operating activities:
Loss from discontinued operations, net of tax	(2)		(20)		15	32
Depreciation, depletion and amortization					62,420	12,864
Bargain purchase gain					1,412	0
Deferred taxes					1,618	15,531
Unrealized foreign exchange loss					313	360
Stock-based compensation					1,254	2,264
Cash settlements paid on exercised stock appreciation rights					(233)	(805)
Derivative instruments (gain) loss, net					(52)	41,300
Cash settlements paid on matured derivative contracts, net					(63)	(33,559)
Cash settlements paid on asset retirement obligations					(374)	0
Credit losses and other	680		571		1,615	1,063
Other operating loss, net					62	5
Operational expenses associated with equipment and other					(1,196)	718
Change in operating assets and liabilities:
Trade receivables					(5,208)	(47,810)
Accounts with joint venture owners					21,746	10,283
Other receivables					(1,868)	(943)
Crude oil inventory					(7,465)	(12,274)
Prepayments and other					(69)	1,570
Value added tax and other receivables					(2,302)	(2,249)
Other long-term assets					1,508	(1,072)
Accounts payable					(10,897)	(857)
Foreign income taxes receivable/payable					15,344	26,093
Deferred tax liability					(3,081)	0
Accrued liabilities and other					(7,137)	29,263
Net cash provided by (used in) continuing operating activities					77,584	69,045
Net cash used in discontinued operating activities					(15)	(38)
Net cash provided by (used in) operating activities					77,569	69,007
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures					(54,832)	(60,278)
Net cash provided by (used in) continuing investing activities					(54,832)	(60,278)
Net cash used in discontinued investing activities					0	0
Net cash provided by (used in) investing activities					(54,832)	(60,278)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock					382	257
Dividend distribution					(13,452)	(3,872)
Treasury shares					(11,403)	(788)
Deferred financing costs					(30)	(1,451)
Payments of finance lease					(3,379)	(68)
Net cash provided by (used in) in continuing financing activities					(27,882)	(5,922)
Net cash used in discontinued financing activities					0	0
Net cash provided by (used in) in financing activities					(27,882)	(5,922)
Effects of exchange rate changes on cash					(285)	0
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH					(5,430)	2,807
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD		$ 59,776		$ 72,314	59,776	72,314	$ 72,314
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$ 54,346		$ 75,121		54,346	75,121	$ 59,776
Supplemental disclosure of cash flow information:
Interest paid, net of amounts capitalized					5,177	113
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period					26,746	29,155
Recognition of right-of-use finance lease assets and liabilities					$ 3,273	$ 1,851

XML

Note 1 - Organization and Accounting Policies

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]

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, natural gas and natural gas liquids ("NGLs") properties. As operator, the Company has production operations and conducts exploration activities in Gabon and Canada and hold interests in two production sharing contracts (“PSCs”) in Egypt. The Company 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 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), 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 unaudited condensed consolidated financial statements (“Financial Statements”) are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results expected for the full year.

These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, which includes a summary of the significant accounting policies.

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 per day through December 2023 by various members in addition to the 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 8 MBbls per day. On June 5, 2023, OPEC meeting Saudi Arabia agreed to an additional 1 MMBbls per day for July 2023 but could be extended. In addition, members of OPEC+ agreed to extend the group's existing supply cuts of 3.7 MMBbls per day for another year ( December 2024). The Company has not received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiatives. 

The average Brent crude oil price for the three months ended June 30, 2023 was $78 per barrel. The average price for all 2022 and 2023 periods are summarized below:

Average Brent Prices	2023		2022
First Quarter	$	81.07	$	100.87
Second Quarter	$	77.99	$	113.84
Third Quarter	$	—	$	100.71
Fourth Quarter	$	—	$	88.72

During the year ended December 31, 2022 and continuing into 2023, the lead times associated with obtaining materials to support its operations and drilling activities have lengthened and, in some cases, prices for fuel, services 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 commodity price environment is still favorable and the Company has not experienced material disruptions to its operations, any factors 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.

Principles of consolidation – The accompanying unaudited condensed consolidated 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 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 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 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 June 30, 2023 and 2022 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”) and representing bank guarantees for customs clearance in Gabon. For Canada, approximately $0.1 million has been set aside as of June 30, 2023 related to property taxes reserved for Mountain View County. Long-term amounts at June 30, 2023 and 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 June 30,
	2023		2022
	(in thousands)
Cash and cash equivalents	$	46,186	$	53,062
Restricted cash - current		113		216
Restricted cash - non-current		1,779		1,752
Abandonment funding		6,268		20,091
Total cash, cash equivalents and restricted cash	$	54,346	$	75,121

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 of the Economic and Monetary Community of Central Africa (CEMAC) of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Etame PSC provides these payments must be denominated in USD and the CEMAC regulations provide for establishment of a USD account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests 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 payment for the years 2019 through 2022 totaling $5.8 million, net to VAALCO based on the 2018 abandonment study. On January 12, 2023, after continued discussions with various BEAC and government officials, the Company was allowed to 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 March 2023. The balance remained unchanged during the second quarter of 2023.

The Company is working on an updated abandonment study with Directorate of Hydrocarbons in Gabon and on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC. 

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. 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, see allowance for credit losses below.

Accounts Receivable, net– The Company’s trade accounts receivable results from sales of crude oil, natural gas, and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses below.

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 produced by the Company was not compatible with the crude oil requirements of the refinery, the Company entered into two contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that produced the compatible oil the refinery required and another contract with the refinery itself to deliver the crude oil. Under the contract with the 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 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 June 30, 2023 condensed consolidated balance sheet are current receivables in the "other, net" line item of approximately $19.7 million for amounts due to the Company from the refinery for 228 MBbls delivered to the refinery, and $19.7 million current liability included in the "Account payable" line item for amounts due to the oil supplier for 228 MBbls of purchased crude oil from the supplier in the second half of 2022 and the first quarter of 2023. A $1.9 million payment was received in July for the receivable related to March deliveries.

On January 19, 2022, TransGlobe’s West Gharib, West Bakr and 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. At June 30, 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 establish third party cargoes to pay the back dated receivable as well as allow third party cargoes against current production

For credit losses associated with other receivables, see allowance for credit losses below.

Value added tax and other receivables, net – 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 June 30, 2023, the outstanding VAT receivable balance, excluding the allowance, was approximately $24.3 million ($15.8 million, net to VAALCO). As of June 30, 2023, the exchange rate was XAF 602.552 = $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 the “Value added tax and 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. The Company is in discussions with the Ministry of Economy and Ministry of Hydrocarbon to obtain a suitable payment plan to address both the back dated VAT and the Government supplied refinery Sogara. VAALCO is in an advanced stage of negotiations for a payment plan resolving this. 

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. 

The Company estimates the current expected credit losses based primarily using 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 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. During the three months ended June 30, 2023, there was no additional provision recorded.

Also on January 1, 2023, the Company transferred its $0.3 million provision related to accounts with joint venture owners from an allowance for bad debt account to an expected credit loss account. An additional $0.2 million was transferred during the second quarter of 2023. As of  June 30, 2023, the Company has established a credit loss allowance for the full $0.5 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  June 30, 2023, the Company recognized an additional $0.5 million related to its Value added tax with Gabon. During the six months ended June 30, 2023, the Company recognized an additional $1.1 million provision related to its Value added tax with Gabon.

With respect to the Company’s receivable from the refinery and 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 the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to 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 June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands)
Allowance for credit losses and other
Balance at beginning of period	$	(12,832	)	$	(6,135	)	$	(8,704	)	$	(5,741	)
Credit loss charges and other, net of receipts		(680	)		(571	)		(1,615	)		(1,063	)
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023		—			—			(3,120	)		—
Foreign currency gain (loss)		(7	)		317			(80	)		415
Balance at end of period	$	(13,519	)	$	(6,389	)	$	(13,519	)	$	(6,389	)

Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon, inventories represent the Company's share of crude oil produced and stored, but unsold at the end of the period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. At June 30, 2023, the Company had 206,136 Bbls of crude oil underlift in Egypt. The Company resolved to sell domestically in the second quarter a proportion of its underlift from the second quarter to ensure an export cargo in August that has now been confirmed with terminal operator. Direct sales to Egypt were higher in the second quarter because of this but allows the Company to thrash out receivable settlements by way of offsets against sister EGPC companies that the Company has utilized in the drilling campaign. The export cargo in the third quarter will allow the Company to receive cash offshore and the Company is currently marketing this cargo with several traders.

Prepayments and Other – Included in “Prepayments and other” line item of the Company’s June 30, 2023 condensed consolidated balance sheet are $2.5 million of prepayments related to fixed assets, $2.7 million of prepayments related to royalties in Gabon, $1.5 million in Gabon and corporate prepaid insurance, $4.0 million related to prepaid fuel in Egypt, $1.9 million in Egyptian advances to contractors, $0.4 million in prepaid Egypt payroll, and $5.1 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, 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. The amount 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, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, 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.

Impairment – The Company reviews the crude oil, 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 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, 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, 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, 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  October 13, 2022, the Company and AcquireCo, an indirect wholly-owned subsidiary of the Company, completed the business acquisition of TransGlobe and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement on  July 13, 2022. The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. To allocate the purchase price, the Company developed fair value models. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 3 for further discussion.

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

Asset retirement obligations (“ARO”) – The Company has obligations to remove tangible equipment and restore land or seabed at the end of crude oil, 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, 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, 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, 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, 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 13 for further discussion.

Revenue recognition – The Company's revenues are derived primarily from contracts with customers. Royalties are considered a cost 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 recognized when the Company satisfies a performance obligation 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 customer and the customer taking physical possession. VAALCO mainly satisfies its performance obligations at a point in time and the amounts of revenues recognized relating to performance obligations satisfied over time are not significant. See Note 6 for further discussion.

In connection with the acquisition of TransGlobe on October 13, 2022, the Company has elected to apply its policy regarding shipping and handling costs and are presenting these costs net within revenue in the consolidated statements of operations and comprehensive income. In addition, the Company has elected to recognize revenue from oil, natural gas and NGL’s based on the Company’s net working interest, less royalties on the consolidated statements of operations and comprehensive income. Any imbalances from an underlift or overlift position are valued based on the 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 15 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.” 

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, 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. The Company also records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil in Gabon which results due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted.

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

In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, the Company has not recognized deferred tax assets. Should the expectations change regarding the expected future tax consequences, the Company may be required to record additional deferred taxes that could have a material effect on the condensed consolidated financial position and results of operations. See Note 16 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 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 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, 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 the Company's review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.

Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, accrued liabilities, liabilities for SARs. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using Level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance sheet while the long-term portion is reported in “Other long-term liabilities”. With respect to 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 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 June 30, 2023
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Assets
Derivative asset	Prepayments and other	$	—	$	158	$	—	$	158
		$	—	$	158	$	—	$	158
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	196	$	—	$	196
		$	—	$	196	$	—	$	196

`		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 the Company'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 June 30, 2023 was 0.738 USD and 0.755, respectively.

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Note 2 - New Accounting Standards

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Accounting Standards Update and Change in Accounting Principle [Text Block]

2. NEW ACCOUNTING STANDARDS 

Adopted

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. ASU 2016-13 is effective for 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 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 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”). The Company recorded an ECL allowance of $3.1 million as an opening balance adjustment to retained earnings at January 1, 2023. See Note 1 for further details.

Not Yet Adopted

In  March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848),” which provides optional expedients and exceptions for applying U.S. GAAP to debt contracts, receivables, leases, derivatives, and other contracts impacted by reference rate reform and other transactions affected by the cessation of the LIBOR. The expiration date of ASU 2020-04 was  December 31, 2022.

In  December 2022, the FASB issued ASU 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848,” to extend the expiration date of Topic 848 through  December 31, 2024. The expedients, if adopted, can be applied prospectively. As the Company implements alternative rates from LIBOR into the Company's current contracts, it is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is discontinued.

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Note 3 - Acquisitions and Dispositions

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Mergers, Acquisitions and Dispositions Disclosures [Text Block]

3. ACQUISITIONS AND DISPOSITIONS

TransGlobe Merger

On October 13, 2022, the Company and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the 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 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 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 Arrangement Agreement.

Prior to the 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 is the accounting acquiror. The purchase accounting for the business combination has not been completed. 

During the three months ended  June 30, 2023 the deferred tax liability in Egypt did not change. During the six months ended June 30, 2023, the deferred tax liability in Egypt was increased by $1.4 million, respectively, as of the date of the Arrangement. This resulted in a decrease to the bargain purchase gain of a corresponding $1.4 million for the six months ended June 30, 2023, and is reflected in VAALCO's condensed consolidated statements of operations in the line, “Other expense, net”. 

The actual impact of the Arrangement was an increase to “Crude oil, natural gas and NGLs sales” of $75.0  million and $1.7  million of “Net income” in the condensed consolidated statements of operations and comprehensive income for the six months ended June 30, 2023. The impact for the three months ended  June 30, 2023 was an increase to “Crude oil, natural gas and NGLs sales” of $31.3  million and $(8.0)  million of “Net Loss” in the condensed consolidated statements of operations and comprehensive income.

	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			Measurement Period Adjustment			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

All assets and liabilities associated with TransGlobe, including crude oil, 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,  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 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 adjustment factors based on reserve category discount rates. Other estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The purchase price allocation is preliminary pending final determination of 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, an initial $10.8 million bargain purchase gain was recognized. As a result of the measurement period adjustment, the initial bargain purchase gain has been reduced to $9.4 million. The bargain purchase gain was due to the decrease in the share price of VAALCO stock from the time period when the arrangement agreement was signed,  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 same. 

The unaudited pro forma results presented below have been prepared to give the effect of the TransGlobe Arrangement discussed above on the Company’s results for the three and six months ended June 30, 2022, as if the Arrangement had been consummated on January 1, 2021. The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the TransGlobe Arrangement had been completed on such date or project the Company’s results of operations for any future date or period.

	Three Months Ended June 30,			Six Months Ended June 30,
	2022			2022
	(in thousands)			(in thousands)
Pro forma (unaudited):
Crude oil, natural gas and natural gas liquids sales	$	183,665	(a)	$	304,792	(a)
Operating income	$	110,091	(b)	$	171,518	(d)
Net income	$	41,818	(c)	$	72,857	(e)
Basic net income per share:	$	0.39		$	0.67
Basic weighted average shares outstanding		108,232			108,121
Diluted net income per share:	$	0.38		$	0.67
Diluted weighted average shares outstanding		108,668			108,585

(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 June 30, 2022 reclassifies depreciation expense, 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 three months ended June 30, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense.
(d)	The unaudited pro forma operating income for the six months ended June 30, 2022 removes the $26.0 million impairment reversal recorded by TransGlobe in 2022, reclassifies depreciation expense, 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.
(e)	The unaudited pro forma net income for the six months ended June 30, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense.

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 consolidated balance sheets. The operating results of the Angola 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 Angola segment from the cash flows from continuing operations for all periods presented in the Company’s consolidated statements of cash flows. During the three and six months ended June 30, 2023 and 2022, the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related 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 and six months ended June 30, 2023, the Yemen segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

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Note 4 - Segment Information

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Segment Reporting Disclosure [Text Block]

4. SEGMENT INFORMATION 

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

Segment activity of continuing operations for the three and six months ended June 30, 2023 and 2022 as well as long-lived assets and segment assets at June 30, 2023 and December 31, 2022 are as follows:

	Three Months Ended June 30, 2023
(in thousands)	Gabon			Egypt			Canada		Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	77,924		$	21,308		$	10,008	$	—		$	—		$	109,240
Operating costs and expenses:
Production expense		23,931			11,089			3,255		386			(57	)		38,604
FPSO Demobilization - Norms Waste Disposal		5,647			—			—		—			—			5,647
Exploration expense		43			14			—		—			—			57
Depreciation, depletion and amortization		19,457			13,757			4,747		—			42			38,003
General and administrative expense		318			202			—		87			4,788			5,395
Credit losses and other		518			—			—		162			—			680
Total operating costs and expenses		49,914			25,062			8,002		635			4,773			88,386
Other operating income (expense), net		(62	)		(241	)		—		—			—			(303	)
Operating income		27,948			(3,995	)		2,006		(635	)		(4,773	)		20,551
Other income (expense):
Derivative instruments loss, net		—			—			—		—			31			31
Interest (expense) income, net		(1,376	)		(503	)		—		—			176			(1,703	)
Other (expense) income, net		(619	)		—			1		—			81			(537	)
Total other expense, net		(1,995	)		(503	)		1		—			288			(2,209	)
Income (loss) from continuing operations before income taxes		25,953			(4,498	)		2,007		(635	)		(4,485	)		18,342
Income tax (benefit) expense		16,251			4,261			—		—			(8,924	)		11,588
Income (loss) from continuing operations		9,702			(8,759	)		2,007		(635	)		4,439			6,754
Loss from discontinued operations, net of tax		—			—			—		—			(2	)		(2	)
Net income (loss)	$	9,702		$	(8,759	)	$	2,007	$	(635	)	$	4,437		$	6,752
Consolidated capital expenditures	$	1,375		$	8,526		$	6,491	$	—		$	36		$	16,427

	Six Months Ended June 30, 2023
(in thousands)	Gabon			Egypt			Canada			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	114,661		$	56,092		$	18,890		$	—		$	—		$	189,643
Operating costs and expenses:
Production expense		38,346			22,199			5,509			748			2			66,804
FPSO Demobilization - Norms Waste Disposal		5,647			—			—			—			—			5,647
Exploration expense		51			14			—			—			—			65
Depreciation, depletion and amortization		29,302			24,552			8,458			—			108			62,420
General and administrative expense		936			381			—			216			9,086			10,619
Credit losses and other		1,453			—			—			162			—			1,615
Total operating costs and expenses		75,735			47,146			13,967			1,126			9,196			147,170
Other operating income, net		(62	)		(241	)		—			—			—			(303	)
Operating income (loss)		38,864			8,705			4,923			(1,126	)		(9,196	)		42,170
Other income (expense):
Derivative instruments gain, net		—			—			—			—			52			52
Interest (expense) income, net		(2,883	)		(1,311	)		(4	)		—			249			(3,949	)
Other income (expense), net		(102	)		—			1			(1	)		(1,575	)		(1,677	)
Total other expense, net		(2,985	)		(1,311	)		(3	)		(1	)		(1,274	)		(5,574	)
Income (loss) from continuing operations before income taxes		35,879			7,394			4,920			(1,127	)		(10,470	)		36,596
Income tax expense (benefit)		22,829			9,253			—			—			(5,723	)		26,359
Income (loss) from continuing operations		13,050			(1,859	)		4,920			(1,127	)		(4,747	)		10,237
Loss from discontinued operations, net of tax		—			—			—			—			(15	)		(15	)
Net income (loss)	$	13,050		$	(1,859	)	$	4,920		$	(1,127	)	$	(4,762	)	$	10,222
Consolidated capital expenditures	$	5,064		$	20,097		$	16,656		$	—		$	36		$	41,852

	Three Months Ended June 30, 2022
(in thousands)	Gabon			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil and natural gas sales	$	110,985		$	—		$	—		$	110,985
Operating costs and expenses:
Production expense		25,360			175			(60	)		25,475
Exploration expense		67			—			—			67
Depreciation, depletion and amortization		8,173			—			18			8,191
General and administrative expense		565			110			2,859			3,534
Bad debt expense and other		571			—			—			571
Total operating costs and expenses		34,736			285			2,817			37,838
Other operating income (expense), net		—			—			—			—
Operating income		76,249			(285	)		(2,817	)		73,147
Other income (expense):
Derivative instruments loss, net		—			—			(9,542	)		(9,542	)
Interest (expense) income, net		(158	)		—			40			(118	)
Other (expense) income, net		(856	)		(1	)		(1,254	)		(2,111	)
Total other expense, net		(1,014	)		(1	)		(10,756	)		(11,771	)
Income from continuing operations before income taxes		75,235			(286	)		(13,573	)		61,376
Income tax (benefit) expense		36,423			1			9,828			46,252
Income from continuing operations		38,812			(287	)		(23,401	)		15,124
Loss from discontinued operations, net of tax		—			—			(20	)		(20	)
Net income	$	38,812		$	(287	)	$	(23,421	)	$	15,104
Consolidated capital expenditures (1)	$	38,102		$	—		$	67		$	38,169

	Six Months Ended June 30, 2022
(in thousands)	Gabon			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil and natural gas sales	$	179,641		$	—		$	—		$	179,641
Operating costs and expenses:
Production expense		43,441			394			—			43,835
Exploration expense		194			—			—			194
Depreciation, depletion and amortization		12,826			—			38			12,864
General and administrative expense		1,158			209			7,161			8,528
Credit losses and other		1,063			—			—			1,063
Total operating costs and expenses		58,682			603			7,199			66,484
Other operating income (expense), net		(5	)		—			—			(5	)
Operating income		120,954			(603	)		(7,199	)		113,152
Other income (expense):
Derivative instruments loss, net		—			—			(41,300	)		(41,300	)
Interest (expense) income, net		(164	)		—			43			(121	)
Other (expense) income, net		(1,494	)		(2	)		(1,311	)		(2,807	)
Total other expense, net		(1,658	)		(2	)		(42,568	)		(44,228	)
Income from continuing operations before income taxes		119,296			(605	)		(49,767	)		68,924
Income tax (benefit) expense		49,256			1			(7,633	)		41,624
Income from continuing operations		70,040			(606	)		(42,134	)		27,300
Loss from discontinued operations, net of tax		—			—			(32	)		(32	)
Net income	$	70,040		$	(606	)	$	(42,166	)	$	27,268
Consolidated capital expenditures (1)	$	69,882		$	—		$	67		$	69,949

(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Corporate and Other		Total
Long-lived assets from continuing operations:
As of June 30, 2023	$	193,501	$	165,813	$	111,677	$	10,000	$	749	$	481,740
As of December 31, 2022 (1)		213,204	$	168,012	$	103,263	$	10,000	$	793	$	495,272

(1) - Includes assets acquired in the TransGlobe acquisition

(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Corporate and Other		Total
Total assets from continuing operations:
As of June 30, 2023	$	384,554	$	270,653	$	118,604	$	11,144	$	44,058	$	829,013
As of December 31, 2022 (1)		395,393	$	293,640	$	110,071	$	10,861	$	45,676	$	855,641

(1) - Includes assets acquired in the 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 was previously party to a COSPA with ExxonMobil Sales and Supply LLC (“Exxon”) that covered sales from February 2020 through July 2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. This COSPA has been terminated.

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 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 an initial aggregate maximum principal amount available of up to $50.0 million. In connection with the 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 crude oil produced from the Etame G4-160 Block, offshore Gabon during the period from August 1, 2022 until the Final Maturity Date of 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.

For the three and six months ended June 30, 2023 sales of crude oil to Glencore made up 100% of Etame revenues. For the three and six months ended June 30, 2022, sales of crude oil to ExxonMobil Sales and Supply LLC made up 100% of Etame revenues. For the three months ended June 30, 2023, the EGPC covered 100% of the Company's crude oil sales in Egypt. For the six months ended June 30, 2023, Mercuria covered 100% of the Company’s crude oil sales in Egypt in the first quarter, while the EGPC covered 100% of sales in the second quarter. For the three and six months ended June 30, 2023, revenues in Canada were concentrated in three separate customers. These customers were Plains Midstream (50.9%), AltaGas (19.1%), and PetroGas Energy (18.60%). Concentrations of accounts receivable are similar to the revenue percentages.

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Note 5 - Earnings Per Share

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Earnings Per Share [Text Block]

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 to net income used in calculating EPS as well as a reconciliation from basic to diluted shares follows: 

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands)
Net income (loss) (numerator):
Income (loss) from continuing operations	$	6,754		$	15,124		$	10,237		$	27,300
Income from continuing operations attributable to unvested shares		(27	)		(229	)		(15	)		(381	)
Numerator for basic		6,727			14,895			10,222			26,919
Loss from continuing operations attributable to unvested shares		—			1			(41	)		2
Numerator for dilutive	$	6,727		$	14,896		$	10,181		$	26,921
Loss from discontinued operations, net of tax	$	(2	)	$	(20	)	$	(15	)	$	(32	)
Loss from discontinued operations attributable to unvested shares		—			—			—			—
Numerator for basic		(2	)		(20	)		(15	)		(32	)
(Income) loss from discontinued operations attributable to unvested shares		—			—			—			—
Numerator for dilutive	$	(2	)	$	(20	)	$	(15	)	$	(32	)
Net income (loss)	$	6,752		$	15,104		$	10,222		$	27,268
Net income attributable to unvested shares		(27	)		(229	)		(56	)		(381	)
Numerator for basic		6,725			14,875			10,166			26,887
Net (income) loss attributable to unvested shares		27			1			41			2
Numerator for dilutive	$	6,752		$	14,876		$	10,125		$	26,889
Weighted average shares (denominator):
Basic weighted average shares outstanding		106,965			58,925			107,175			58,814
Effect of dilutive securities		648			436			875			464
Diluted weighted average shares outstanding		107,613			59,361			108,050			59,278
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		431			251			238			154

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Note 6 - Revenue

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Revenue from Contract with Customer [Text Block]

6. REVENUE

Gabon

Revenues from contracts with customers are generated from sales in Gabon pursuant to 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 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 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), 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 sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. Historically, 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 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 about applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, the Company deemed this situation to be characterized as a fixed price situation.

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

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

With respect to the government’s share of Profit Oil, the Etame PSC provides that the corporate income tax liability may be satisfied through the payment of Profit Oil. In the condensed consolidated statements of operations 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 the 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 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 $16.7 million foreign income tax payable as of  June 30, 2023 related to Gabon. As of December 31, 2022, the Company had a foreign taxes receivable of $2.8 million, as the Gabonese government lifted more oil-in-kind than what was 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 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 June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Revenues from customer contracts:	(in thousands)
Sales under the COSPA or COSMA	$	87,478		$	125,143		$	130,079		$	201,629
Other items reported in revenue not associated with customer contracts:
Carried interest recoupment		2,212			2,371			2,212			3,483
Royalties		(11,766	)		(16,529	)		(17,630	)		(25,471	)
Net revenues	$	77,924		$	110,985		$	114,661		$	179,641

Egypt

Revenues from sales in Egypt are generally made through direct sales to EGPC or through contracts with customers pursuant to COSPAs 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.

Customer sales generally occur daily 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 the EGPC storage facility, and the Company has elected to sell domestically to EGPC. When sales are made through a 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 (currently around 4.9%) and is shared with the Egyptian government through the PSCs and their government take. 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 production (take)will 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 because of direct marketing to international purchasers. Depending on the Company's assessment of the credit of crude oil cargo buyers, customers  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 one to two months from delivery. 

In some instances, TPI will borrow or loan production volumes 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 June 30,			Six Months Ended June 30,
	2023			2023
Revenues from customer contracts:	(in thousands)
Gross sales	$	50,201		$	104,822
Royalties		(28,892	)		(48,232	)
Selling costs		(1	)		(498	)
Net revenues	$	21,308		$	56,092

Canada

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. 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 to in exchange for transferring promised goods to a customer and 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 revenue net of royalties.

Customer sales generally occur daily 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 types 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 June 30,			Six Months Ended June 30,
	2023			2023
Revenues from customer contracts:	(in thousands)
Oil revenue	$	8,325		$	14,979
Gas revenue		703			1,661
NGL revenue		1,885			4,348
Royalties		(905	)		(2,098	)
Net revenues	$	10,008		$	18,890

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Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Oil and Gas Properties [Text Block]

7. CRUDE OIL, 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 June 30, 2023			As of December 31, 2022
	(in thousands)
Crude oil, natural gas and NGLs properties and equipment - successful efforts method:
Wells, platforms and other production facilities	$	1,446,801		$	1,406,888
Work-in-progress		—			—
Undeveloped acreage		54,346			56,251
Equipment and other		43,835			38,796
		1,544,982			1,501,935
Accumulated depreciation, depletion, amortization and impairment		(1,063,242	)		(1,006,663	)
Net crude oil, natural gas and NGLs properties, equipment and other	$	481,740		$	495,272

Etame Marin Block PSC

On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the “Etame Consortium”), received a Presidential Decree for an extension (“PSC Extension”) to the Etame Consortium to operate in the Etame Marin block. The PSC Extension extends the term to operate until September 17, 2028. The PSC Extension also grants the Etame Consortium the right for two additional extension periods of five years each. 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.

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

Egypt PSCs

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 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 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 of royalty on 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 the Company's PSCs.

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	%

(1) - Represents the year acquired by TransGlobe, prior to the Arrangement.

*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

Equatorial Guinea PSC

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 first 10,000 bopd, and 11% for the 10,000 bopd to 25,000 bopd tranche. The Government of Equatorial Guinea'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 Government of Equatorial Guinea'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. 

Proved Properties

The Company reviews the crude oil, 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, 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 three months ended June 30, 2023 that would cause the Company to believe the value of crude oil, natural gas and NGLs producing properties should be impaired. Factors considered included higher forward prices from June 30, 2023 and capital expenditures in the period related to its reserves in Gabon, Egypt and Canada. 

Undeveloped Leasehold Costs 

Equatorial Guinea

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 the Company's appointment as the operator 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”) if 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 non-defaulting parties assigned the defaulting party’s interest to the non-defaulting parties as required by the Joint Operating Agreement. As a result, VAALCO’s working interest increased to 45.9% when the EG MMH approved the fourth amendment to the production sharing contract. In February of 2023, the Company 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 at first commercial production of the Block.

The Company has completed a feasibility study of the development concept of the Venus discovery on Block P. On September 16, 2022, the EG MMH approved the submitted plan of development. Final documents to affect the plan of development are subject to EG MMH approval. The 2023 budget for the plan was delivered on October 12, 2022 to the MMH and 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 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 for the area associated with the Venus development. As of June 30, 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 discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $6.7 million of the share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame Marin block PSC. As a result of discovering reserves in connection with drilling the South East Etame 4H development well in March 2020, $2.3 million of costs were transferred to proved leasehold costs leaving a remaining $11.5 million in unproved leasehold costs. In connection with the Sasol Acquisition discussed under Note 3, $2.2 million of reserves were attributed to undeveloped properties. The balance of undeveloped leasehold costs related to the Etame Marin block at June 30, 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 June 30, 2023, the undeveloped leasehold costs for Egypt was $13.9 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 expense, net” line item of the unaudited condensed consolidated statements of operations and comprehensive income but were not material for the three and six months ended June 30, 2023 and 2022.

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Note 8 - Derivatives and Fair Value

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Derivatives and Fair Value [Text Block]

8. DERIVATIVES

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. See the table below for the list of outstanding contracts as of June 30, 2023:

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

While these 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 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 purposes. 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 Company has not yet drawn down on its available facility.

The 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 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" 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 and comprehensive income:

		Three Months Ended June 30,						Six Months Ended June 30,
Derivative Item	Statements of Operations Line	2023			2022			2023			2022
		(in thousands)						(in thousands)
Commodity derivatives	Cash settlements paid on matured derivative contracts, net	$	(4	)	$	(21,059	)	$	(63	)	$	(33,559	)
	Unrealized gain (loss)		35			11,517			115			(7,741	)
	Derivative instruments gain (loss), net	$	31		$	(9,542	)	$	52		$	(41,300	)

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Note 9 - Accrued Liabilities and Other

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block]

9. CURRENT ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:

	As of June 30, 2023		As of December 31, 2022
	(in thousands)
Accrued accounts payable invoices	$	21,480	$	28,360
Gabon DMO, PID and PIH obligations		12,782		10,509
Capital expenditures		19,770		26,618
Stock appreciation rights – current portion		32		570
Accrued wages and other compensation		2,726		8,161
ARO Obligation		5,729		306
Egypt modernization payments		9,373		9,933
Excess cost oil payable		8,099		—
Other		4,113		6,935
Total accrued liabilities and other	$	84,104	$	91,392

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Note 10 - Commitments and Contingencies

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Commitments and Contingencies Disclosure [Text Block]

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 (prior to the decommissioning of the FPSO Nautipa which occurred in February 2023), and the estimate used for this purpose is approximately $81.3 million ($47.8 million, net to VAALCO) on an undiscounted basis. The abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the Etame PSC. At  June 30, 2023, the balance of the abandonment fund was $10.7 million ($6.3 million, net to VAALCO) on an undiscounted 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.

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 March 2023. No activity was noted in the abandonment funding account during the second quarter of 2023. 

FPSO charter

In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter could be extended for two one-year periods beyond September 2020. These elections were made, and the charter was extended through September 2022. On September 9, 2022, the Company signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022 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 on a gross basis, $8.9 million net to 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 settle on the Company’s restricted cash balances associated with the FPSO. In the second quarter of 2023, it was determined that there was more waste than anticipated connected to the FPSO from VAALCO's usage. As such, VAALCO incurred an additional $5.6 million in decommissioning fees, which was reported as a separate line item on the income statement. 

During the second quarter of 2023, the Joint Operating Group were informed by BW Offshore the supplier of the former FPSO that waste disposal of naturally occurring radioactive material was present in the final volumes and tanks on the vessel as is typical. The JOA have an obligation to lift and properly dispose of this waste. The Company has provided for an accrual for the collection and disposal of the waste via tank cleaning activities that will occur in September and October 2023. The cost is expected to be around $9.6 million gross ($5.6 million net to VAALCO).

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. The Company is working with the 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 received the findings from this audit and has responded to the audit findings and are working with the government of Gabon on the results of the 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.

Dividend Policy

On November 3, 2021, the Company announced that the Company’s board of directors adopted a cash dividend policy. 

On May 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share, which was paid on  June 23, 2023 to stockholders of record at the close of business on May 24, 2023. On August 9, 2023, the Company's board of directors declared a quarterly cash dividend of $0.0625 per common share to be paid on September 22, 2023 to stockholders of record at the close of business on August 25, 2023. 

In connection with the RBL facility, discussed in Note 11 to the Financial Statements, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. If 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 to make distributions, buyback shares, or repurchase stock. For the six months ended  June 30, 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 considering 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 up to 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. 

The following table shows the repurchases of equity securities related to the share repurchase program after March 31, 2023 through June 30, 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
April 1, 2023 - April 30, 2023		303,969	$	4.94		303,969	$	21,003,245
May 1, 2023 - May 31, 2023		362,843	$	4.14		362,843	$	19,502,740
June 1, 2023 - June 30, 2023		494,164	$	4.05		494,164	$	17,504,007
Total		1,160,976				1,160,976

The following table shows the repurchases of equity securities related to the share repurchase program after June 30, 2023 through  August 4, 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
July 1, 2023 - July 31, 2023		505,720		$3.96		505,720		$15,504,180
August 1, 2023 - August 4, 2023		98,411		$4.29		98,411		$15,082,133
Total		604,131				604,131

The actual timing number and value of shares repurchased under the share buyback program will depend on several 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 condition's 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 $26.8 million at June 30, 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 $17.5 million was recorded in "Other long-term liabilities". 

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 June 30, 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 because 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 June 30, 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 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 Sogara 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 two contracts (buy/sell arrangements) to fulfill its domestic market needs obligation under the Etame PSC. One contract is to purchase oil from another provider (currently Perenco – the supplier) that produces the compatible oil to meet the needs of the 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. At June 30, 2023, the amount due to the Company from the refinery is $19.7 million. A separate credit loss of $3.1 million has been provided for. 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 Company. The Company expects to recover the full amount receivable owed to it for both the VAT receivable and receivable under the oil supply arrangement, but the terms of recovery have not fully been finalized. 

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Note 11 - Debt

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Debt Disclosure [Text Block]

11. DEBT

As of  June 30, 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 reduced by $6.25 million.

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. 

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 June 30, 2023, the Company's borrowing base was $50.0 million. The amount the Company can borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. Regarding the requirement, the Company must 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 June 30, 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 $1.7 million, ($2.1 million net of accumulated amortization of $0.4 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.

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Note 12 - Leases

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Operating and Finance Leases [Text Block]

12. LEASES

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.

Operating leases

The Company is currently a party to several operating lease agreements for the corporate office, rental of marine vessels and equipment and a drilling rig used in the Company’s Egyptian operations. The duration for these agreements ranges from 5 to 21 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for marine vessels, and certain equipment used in the joint operations includes the gross amount of the lease components.

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

Financing leases

The Company is currently a party to several financing lease agreements for the FSO and generators used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. The duration for these agreements ranges from 4 to 111 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities.

All leases

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

For the three and six months ended June 30, 2023 and 2022, the components of the lease costs and the supplemental information were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Lease cost:	(in thousands)
Finance lease cost (1)	$	4,115	$	98	$	8,480	$	164
Operating lease cost		339		4,265		922		8,461
Short-term lease cost (2)		1,660		199		3,020		1,213
Variable lease cost (3)		—		1,909		—		3,247
Total lease expense		6,114		6,471		12,422		13,085
Lease costs capitalized		7		651		55		1,423
Total lease costs	$	6,121	$	7,122	$	12,477	$	14,508

	Six Months Ended June 30,
	2023			2022
Other information:
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash flows attributable to finance leases (in thousands)	$	3,379		$	26
Weighted-average remaining lease term (in years)		8.96			5.17
Weighted-average discount rate		8.11	%		3.54	%
Operating cash flows attributable to operating leases (in thousands)	$	423		$	12,816
Weighted-average remaining lease term (in years)		0.95			0.70
Weighted-average discount rate		10.33	%		5.62	%

(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 statements of 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(in thousands)
Finance lease cost	$	2,376	$	57	$	5,001	$	96
Production expense		1,208		3,720		2,494		7,558
General and administrative expense		52		47		98		63
Lease costs billed to the joint venture owners		2,481		2,884		4,849		5,886
Total lease expense		6,117		6,708		12,442		13,603
Lease costs capitalized		4		414		35		905
Total lease costs	$	6,121	$	7,122	$	12,477	$	14,508

The following table describes the future maturities of the Company’s lease liabilities at June 30, 2023:

	Operating Leases		Finance Leases
Year	(in thousands)
2023	$	1,173	$	7,287
2024		672		14,448
2025		32		16,202
2026		—		16,478
2027		—		15,023
Thereafter		—		51,527
		1,877		120,965
Less: imputed interest		80		33,425
Total lease liabilities	$	1,797	$	87,540

Under the joint operating agreements, other joint venture owners are obligated to fund $49.8 million of the $122.8 million in future lease liabilities.

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Note 13 - Asset Retirement Obligations

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Asset Retirement Obligation Disclosure [Text Block]

13. ASSET RETIREMENT OBLIGATIONS 

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

(in thousands)	As of June 30, 2023			As of December 31, 2022
Beginning balance	$	42,001		$	40,694
Accretion		1,118			1,958
Additions		—			6,134
Revisions		5,726			(43	)
Settlements		(374	)		(6,577	)
Foreign currency gain (loss)		216			(165	)
Ending balance	$	48,687		$	42,001

 

Accretion is recorded in the line item “Depreciation, depletion and amortization” in the unaudited condensed consolidated statements of 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. As a result of the expected timing of the end of the FPSO contract, included in the line item "Accrued liabilities and other" in the unaudited condensed consolidated balance sheet is $5.6 million of costs associated with the retirement obligation as of June 30, 2023. The accrual is primarily related to the FPSO waste disposal discussed in detail in the commitments and contingencies footnote. 

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.

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 June 30, 2023 and 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.

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Note 14 - Shareholders' Equity

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Equity [Text Block]

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. No shares of preferred stock were issued and outstanding as of June 30, 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 up to 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 June 30, 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
April 1, 2023 - April 30, 2023		303,969	$	4.94		303,969	$	21,003,245
May 1, 2023 - May 31, 2023		362,843	$	4.14		362,843	$	19,502,740
June 1, 2023 - June 30, 2023		494,164	$	4.05		494,164	$	17,504,007
Total		1,160,976				1,160,976

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 the Company's financial statements as they reduce the number of shares that would have been issued upon vesting. See Note 15 for further discussion.

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Note 15 - Stock-based Compensation and Other Benefit Plans

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Share-Based Payment Arrangement [Text Block]

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 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At June 30, 2023, under the 2020 Plan, 1,718,603 shares were available for future grants.

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

As referenced in the table below, the Company records compensation expenses 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 six months ended June 30, 2023, the Company settled in cash $0.2 million for stock appreciation rights and received $0.4 million for stock option exercises. During the six months ended June 30, 2022, the Company settled in cash $0.8 million for stock appreciation rights and received $0.3 million for stock option exercises.

	Three Months Ended June 30,					Six Months Ended June 30,
	2023			2022		2023			2022
	(in thousands)
Stock-based compensation - equity awards	$	706		$	615	$	1,381		$	1,019
Stock-based compensation - liability awards		(101	)		227		(127	)		1,245
Total stock-based compensation	$	605		$	842	$	1,254		$	2,264

Stock options and performance shares

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

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.

In June 2023, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 334,753 shares at an exercise price of $4.19 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 $4.82 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 $5.54 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 $6.37 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.

During the six months ended June 30, 2023 and 2022, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo. 

	Six Months Ended June 30,
	2023			2022
Weighted average exercise price - ($/share)	$	4.19		$	6.41
Expected life in years		6.4			6.0
Average expected volatility		68	%		72	%
Risk-free interest rate		3.73	%		1.98	%
Expected dividend yield		5.97	%		2.30	%
Weighted average grant date fair value - ($/share)	$	2.29		$	2.84

Stock option activity associated with performance options for the six months ended June 30, 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		$	3.95
Granted		335			4.19
Exercised		(74	)		(1.68	)
Unvested shares forfeited		—			—
Vested shares expired		—			—
Outstanding at June 30, 2023		705		$	4.30			8.95	$	280
Exercisable at June 30, 2023		211		$	3.34			7.70	$	262

Stock option activity associated with plain vanilla options for the six months ended June 30, 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		(164	)		(1.56	)
Unvested shares forfeited		—			—
Vested shares expired		—			—
Outstanding at June 30, 2023		223		$	2.07			0.73	$	376
Exercisable at June 30, 2023		223		$	2.07			0.73	$	376

As a result of tax withholding on options exercised, 44,655 shares were added to treasury during the six months ended June 30, 2023.

Restricted shares

Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three-year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant). The vesting of 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 six months ended June 30, 2023:

	Restricted Stock			Weighted Average Grant Date Fair Value
	(in thousands)
Non-vested shares outstanding at January 1, 2023		665		$	4.59
Awards granted		797			4.19
Awards vested		(354	)		3.92
Awards forfeited		(12	)		5.73
Non-vested shares outstanding at June 30, 2023		1,096		$	4.51

During the six months ended June 30, 2023, 81,342 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. 

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, 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 RSU activity for the six months ended June 30, 2023:

	Restricted Stock			Weighted Average Conversion Date Fair Value
	(in thousands)
Non-vested shares outstanding at January 1, 2023		383		$	4.27
Awards granted		183			4.19
Awards vested		(259	)		4.27
Awards forfeited		(23	)		4.27
Non-vested shares outstanding at June 30, 2023		284		$	4.22

During the six months ended June 30, 2023, 162,328 shares were added to treasury because of tax withholding on the vesting of RSU’s.

PSUs are like 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 six months ended June 30, 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		(514	)		4.27
Awards forfeited		(36	)		4.27
Non-vested shares outstanding at June 30, 2023		140		$	4.27

During the six months ended June 30, 2023, 147,862 shares were added to treasury as a result of tax withholding on the vesting of PSU’s.

DSUs are like 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 the Company'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 June 30, 2023, approximately 101,313 DSUs are vested but not converted. During the second quarter of 2023, 358,563 DSUs were converted to shares of common stock of the company following the departure of Mr. David Cook and Mr. Timothy Marchant from the board of directors, of which 65,582 shares were forfeited back to VAALCO to satisfy applicable tax withholding obligations.

Stock appreciation rights (“SARs”)

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

During the six months ended June 30, 2023, the Company did not grant SARs to employees or directors.

SAR activity for the six months ended June 30, 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 June 30, 2023		139		$	2.33		0.64	$	198
Exercisable at June 30, 2023		139		$	2.33		0.64	$	198

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 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.

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Note 16 - Income Taxes

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Income Tax Disclosure [Text Block]

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 that include Canada, Egypt, Equatorial Guinea and Gabon.

Income taxes attributable to continuing operations for the three and six months ended June 30, 2023 and 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:

	Three Months Ended June 30,					Six Months Ended June 30,
	2023			2022		2023		2022
U.S. Federal:	(in thousands)
Current	$	—		$	—	$	—	$	—
Deferred		871			2,617		1,457		(9,869	)
Foreign:
Current		12,401			20,402		24,701		26,093
Deferred		(1,684	)		23,233		201		25,400
Total	$	11,588		$	46,252	$	26,359	$	41,624

The Company’s effective tax rate for the three and six months ended  June 30, 2023, excluding the impact of discrete items, was 68.42% and 63.32%. For the three and six months ended June 30, 2022, the effective tax rates were 73.37% and 72.59%. The total tax expense for the three months ended June 30, 2023, includes a discrete amount of ($0.5) million primarily related to adjustments made because of changes to oil price (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, i.e., oil price adjustment). For the six months ended June 30, 2023, the current tax expense of $24.7  million includes a $2.7 million unfavorable oil price adjustment. After excluding that impact, current income taxes were an expense of $22.0 million for the period. For the three months ended June 30, 2022, the current tax expense of $20.4 million includes a $1.2 million unfavorable oil price adjustment. After excluding this impact, current income taxes were $19.2 million for the period. For the six months ended June 30, 2022, the Company’s overall effective tax rate was appreciably impacted by non-deductible items associated with operations (which includes losses on derivative instruments) and the release of valuation allowance attributable to the current period. The total tax expense for the six months ended June 30, 2022 includes a discrete adjustment for the release of an additional $12.7 million of valuation allowance as a result of an increase in forecasted future earnings. For the six months ended June 30, 2022, the current tax expense of $26.1 million includes a $4.3 million unfavorable oil price adjustment. After excluding the impact, current income taxes were $21.8 million for the period.

As of June 30, 2023, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.

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Note 17 - Other Comprehensive Income

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Comprehensive Income (Loss) Note [Text Block]

17. OTHER COMPREHENSIVE INCOME 

The Company’s other comprehensive income was $2.0 million for the three months ended June 30, 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
Accumulated other comprehensive income (loss) before reclassifications		2,006
Balance at June 30, 2023	$	3,060

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Item 5 - Other Information

6 Months Ended

Jun. 30, 2023

Notes to Financial Statements

Issuer Rule 10b5-1, Material Terms [Text Block]

 ITEM 5. OTHER INFORMATION

During the three months ended June 30, 2023, none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act)

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Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2023

Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

Principles of consolidation – The accompanying unaudited condensed consolidated 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, Policy [Policy Text Block]

Use of estimates – The preparation of the Financial Statements in conformity with 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 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, Policy [Policy Text Block]

Cash and cash equivalents – Cash and cash equivalents 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.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts in restricted cash at June 30, 2023 and 2022 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”) and representing bank guarantees for customs clearance in Gabon. For Canada, approximately $0.1 million has been set aside as of June 30, 2023 related to property taxes reserved for Mountain View County. Long-term amounts at June 30, 2023 and 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 June 30,
	2023		2022
	(in thousands)
Cash and cash equivalents	$	46,186	$	53,062
Restricted cash - current		113		216
Restricted cash - non-current		1,779		1,752
Abandonment funding		6,268		20,091
Total cash, cash equivalents and restricted cash	$	54,346	$	75,121

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 of the Economic and Monetary Community of Central Africa (CEMAC) of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Etame PSC provides these payments must be denominated in USD and the CEMAC regulations provide for establishment of a USD account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests 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 payment for the years 2019 through 2022 totaling $5.8 million, net to VAALCO based on the 2018 abandonment study. On January 12, 2023, after continued discussions with various BEAC and government officials, the Company was allowed to 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 March 2023. The balance remained unchanged during the second quarter of 2023.

The Company is working on an updated abandonment study with Directorate of Hydrocarbons in Gabon and on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC. 

Interest in Unincorporated Joint Ventures or Partnerships, Policy [Policy Text Block]

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. 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, see allowance for credit losses below.

Accounts Receivable [Policy Text Block]

Accounts Receivable, net– The Company’s trade accounts receivable results from sales of crude oil, natural gas, and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses below.

Other Receivables [Policy Text Block]

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 produced by the Company was not compatible with the crude oil requirements of the refinery, the Company entered into two contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that produced the compatible oil the refinery required and another contract with the refinery itself to deliver the crude oil. Under the contract with the 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 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 June 30, 2023 condensed consolidated balance sheet are current receivables in the "other, net" line item of approximately $19.7 million for amounts due to the Company from the refinery for 228 MBbls delivered to the refinery, and $19.7 million current liability included in the "Account payable" line item for amounts due to the oil supplier for 228 MBbls of purchased crude oil from the supplier in the second half of 2022 and the first quarter of 2023. A $1.9 million payment was received in July for the receivable related to March deliveries.

On January 19, 2022, TransGlobe’s West Gharib, West Bakr and 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. At June 30, 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 establish third party cargoes to pay the back dated receivable as well as allow third party cargoes against current production

For credit losses associated with other receivables, see allowance for credit losses below.

Taxes and Other Receivables [Policy Text Block]

Value added tax and other receivables, net – 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 June 30, 2023, the outstanding VAT receivable balance, excluding the allowance, was approximately $24.3 million ($15.8 million, net to VAALCO). As of June 30, 2023, the exchange rate was XAF 602.552 = $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 the “Value added tax and 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. The Company is in discussions with the Ministry of Economy and Ministry of Hydrocarbon to obtain a suitable payment plan to address both the back dated VAT and the Government supplied refinery Sogara. VAALCO is in an advanced stage of negotiations for a payment plan resolving this. 

Credit Loss, Financial Instrument [Policy Text Block]

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. 

The Company estimates the current expected credit losses based primarily using 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 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. During the three months ended June 30, 2023, there was no additional provision recorded.

Also on January 1, 2023, the Company transferred its $0.3 million provision related to accounts with joint venture owners from an allowance for bad debt account to an expected credit loss account. An additional $0.2 million was transferred during the second quarter of 2023. As of  June 30, 2023, the Company has established a credit loss allowance for the full $0.5 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  June 30, 2023, the Company recognized an additional $0.5 million related to its Value added tax with Gabon. During the six months ended June 30, 2023, the Company recognized an additional $1.1 million provision related to its Value added tax with Gabon.

With respect to the Company’s receivable from the refinery and 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 the Economy, Hydrocarbons and the Presidency of Gabon on finding a solution to 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 June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands)
Allowance for credit losses and other
Balance at beginning of period	$	(12,832	)	$	(6,135	)	$	(8,704	)	$	(5,741	)
Credit loss charges and other, net of receipts		(680	)		(571	)		(1,615	)		(1,063	)
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023		—			—			(3,120	)		—
Foreign currency gain (loss)		(7	)		317			(80	)		415
Balance at end of period	$	(13,519	)	$	(6,389	)	$	(13,519	)	$	(6,389	)

Inventory, Policy [Policy Text Block]

Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon, inventories represent the Company's share of crude oil produced and stored, but unsold at the end of the period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. At June 30, 2023, the Company had 206,136 Bbls of crude oil underlift in Egypt. The Company resolved to sell domestically in the second quarter a proportion of its underlift from the second quarter to ensure an export cargo in August that has now been confirmed with terminal operator. Direct sales to Egypt were higher in the second quarter because of this but allows the Company to thrash out receivable settlements by way of offsets against sister EGPC companies that the Company has utilized in the drilling campaign. The export cargo in the third quarter will allow the Company to receive cash offshore and the Company is currently marketing this cargo with several traders.

Prepayments and Other [Policy Text Block]

Prepayments and Other – Included in “Prepayments and other” line item of the Company’s June 30, 2023 condensed consolidated balance sheet are $2.5 million of prepayments related to fixed assets, $2.7 million of prepayments related to royalties in Gabon, $1.5 million in Gabon and corporate prepaid insurance, $4.0 million related to prepaid fuel in Egypt, $1.9 million in Egyptian advances to contractors, $0.4 million in prepaid Egypt payroll, and $5.1 million in other prepaid items.

Inventory Supplies, Policy [Policy Text Block]

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.

Oil and Gas Properties Policy [Policy Text Block]

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

Exploratory Drilling Costs Capitalization and Impairment, Policy [Policy Text Block]

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. The amount 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 [Policy Text Block]

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, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, 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.

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Impairment – The Company reviews the crude oil, 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 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, 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, 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, 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.

Business Combinations Policy [Policy Text Block]

Purchase Accounting – On  October 13, 2022, the Company and AcquireCo, an indirect wholly-owned subsidiary of the Company, completed the business acquisition of TransGlobe and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement on  July 13, 2022. The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. To allocate the purchase price, the Company developed fair value models. 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.

Lessee, Leases [Policy Text Block]

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

Asset Retirement Obligation [Policy Text Block]

Asset retirement obligations (“ARO”) – The Company has obligations to remove tangible equipment and restore land or seabed at the end of crude oil, 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, 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, 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, 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, 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 13 for further discussion.

Revenue from Contract with Customer [Policy Text Block]

Revenue recognition – The Company's revenues are derived primarily from contracts with customers. Royalties are considered a cost 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 recognized when the Company satisfies a performance obligation 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 customer and the customer taking physical possession. VAALCO mainly satisfies its performance obligations at a point in time and the amounts of revenues recognized relating to performance obligations satisfied over time are not significant. See Note 6 for further discussion.

In connection with the acquisition of TransGlobe on October 13, 2022, the Company has elected to apply its policy regarding shipping and handling costs and are presenting these costs net within revenue in the consolidated statements of operations and comprehensive income. In addition, the Company has elected to recognize revenue from oil, natural gas and NGL’s based on the Company’s net working interest, less royalties on the consolidated statements of operations and comprehensive income. Any imbalances from an underlift or overlift position are valued based on the actual sales proceeds received.

Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]

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.

Share-Based Payment Arrangement [Policy Text Block]

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 15 for further discussion.

Foreign Currency Transactions and Translations Policy [Policy Text Block]

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.” 

Income Tax, Policy [Policy Text Block]

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, 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. The Company also records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil in Gabon which results due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted.

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

In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, the Company has not recognized deferred tax assets. Should the expectations change regarding the expected future tax consequences, the Company may be required to record additional deferred taxes that could have a material effect on the condensed consolidated financial position and results of operations. See Note 16 for further discussion.

Derivatives, Policy [Policy Text Block]

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 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 and comprehensive income. See Note 8 for further discussion.

Fair Value Measurement, Policy [Policy Text Block]

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 [Policy Text Block]

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, 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 the Company's review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.

Fair Value of Financial Instruments, Policy [Policy Text Block]

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. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using Level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance sheet while the long-term portion is reported in “Other long-term liabilities”. With respect to 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 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 June 30, 2023
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Assets
Derivative asset	Prepayments and other	$	—	$	158	$	—	$	158
		$	—	$	158	$	—	$	158
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	196	$	—	$	196
		$	—	$	196	$	—	$	196

`		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, Policy [Policy Text Block]

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 Policy [Policy Text Block]

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. 

Comprehensive Income, Policy [Policy Text Block]

Other comprehensive income – All of the Company’s other comprehensive income arises from the Company'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 June 30, 2023 was 0.738 USD and 0.755, respectively.

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Note 1 - Organization and Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Oil and Gas, Average Sale Price and Production Cost [Table Text Block]

Average Brent Prices	2023		2022
First Quarter	$	81.07	$	100.87
Second Quarter	$	77.99	$	113.84
Third Quarter	$	—	$	100.71
Fourth Quarter	$	—	$	88.72

Schedule of Cash, Cash Equivalents and Restricted Cash [Table Text Block]

	As of June 30,
	2023		2022
	(in thousands)
Cash and cash equivalents	$	46,186	$	53,062
Restricted cash - current		113		216
Restricted cash - non-current		1,779		1,752
Abandonment funding		6,268		20,091
Total cash, cash equivalents and restricted cash	$	54,346	$	75,121

Accounts Receivable, Allowance for Credit Loss [Table Text Block]

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands)
Allowance for credit losses and other
Balance at beginning of period	$	(12,832	)	$	(6,135	)	$	(8,704	)	$	(5,741	)
Credit loss charges and other, net of receipts		(680	)		(571	)		(1,615	)		(1,063	)
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023		—			—			(3,120	)		—
Foreign currency gain (loss)		(7	)		317			(80	)		415
Balance at end of period	$	(13,519	)	$	(6,389	)	$	(13,519	)	$	(6,389	)

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

		As of June 30, 2023
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Assets
Derivative asset	Prepayments and other	$	—	$	158	$	—	$	158
		$	—	$	158	$	—	$	158
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	196	$	—	$	196
		$	—	$	196	$	—	$	196

`		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

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Note 3 - Acquisitions and Dispositions (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

	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			Measurement Period Adjustment			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

Business Acquisition, Pro Forma Information [Table Text Block]

	Three Months Ended June 30,			Six Months Ended June 30,
	2022			2022
	(in thousands)			(in thousands)
Pro forma (unaudited):
Crude oil, natural gas and natural gas liquids sales	$	183,665	(a)	$	304,792	(a)
Operating income	$	110,091	(b)	$	171,518	(d)
Net income	$	41,818	(c)	$	72,857	(e)
Basic net income per share:	$	0.39		$	0.67
Basic weighted average shares outstanding		108,232			108,121
Diluted net income per share:	$	0.38		$	0.67
Diluted weighted average shares outstanding		108,668			108,585

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Note 4 - Segment Information (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Three Months Ended June 30, 2023
(in thousands)	Gabon			Egypt			Canada		Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	77,924		$	21,308		$	10,008	$	—		$	—		$	109,240
Operating costs and expenses:
Production expense		23,931			11,089			3,255		386			(57	)		38,604
FPSO Demobilization - Norms Waste Disposal		5,647			—			—		—			—			5,647
Exploration expense		43			14			—		—			—			57
Depreciation, depletion and amortization		19,457			13,757			4,747		—			42			38,003
General and administrative expense		318			202			—		87			4,788			5,395
Credit losses and other		518			—			—		162			—			680
Total operating costs and expenses		49,914			25,062			8,002		635			4,773			88,386
Other operating income (expense), net		(62	)		(241	)		—		—			—			(303	)
Operating income		27,948			(3,995	)		2,006		(635	)		(4,773	)		20,551
Other income (expense):
Derivative instruments loss, net		—			—			—		—			31			31
Interest (expense) income, net		(1,376	)		(503	)		—		—			176			(1,703	)
Other (expense) income, net		(619	)		—			1		—			81			(537	)
Total other expense, net		(1,995	)		(503	)		1		—			288			(2,209	)
Income (loss) from continuing operations before income taxes		25,953			(4,498	)		2,007		(635	)		(4,485	)		18,342
Income tax (benefit) expense		16,251			4,261			—		—			(8,924	)		11,588
Income (loss) from continuing operations		9,702			(8,759	)		2,007		(635	)		4,439			6,754
Loss from discontinued operations, net of tax		—			—			—		—			(2	)		(2	)
Net income (loss)	$	9,702		$	(8,759	)	$	2,007	$	(635	)	$	4,437		$	6,752
Consolidated capital expenditures	$	1,375		$	8,526		$	6,491	$	—		$	36		$	16,427

	Six Months Ended June 30, 2023
(in thousands)	Gabon			Egypt			Canada			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	114,661		$	56,092		$	18,890		$	—		$	—		$	189,643
Operating costs and expenses:
Production expense		38,346			22,199			5,509			748			2			66,804
FPSO Demobilization - Norms Waste Disposal		5,647			—			—			—			—			5,647
Exploration expense		51			14			—			—			—			65
Depreciation, depletion and amortization		29,302			24,552			8,458			—			108			62,420
General and administrative expense		936			381			—			216			9,086			10,619
Credit losses and other		1,453			—			—			162			—			1,615
Total operating costs and expenses		75,735			47,146			13,967			1,126			9,196			147,170
Other operating income, net		(62	)		(241	)		—			—			—			(303	)
Operating income (loss)		38,864			8,705			4,923			(1,126	)		(9,196	)		42,170
Other income (expense):
Derivative instruments gain, net		—			—			—			—			52			52
Interest (expense) income, net		(2,883	)		(1,311	)		(4	)		—			249			(3,949	)
Other income (expense), net		(102	)		—			1			(1	)		(1,575	)		(1,677	)
Total other expense, net		(2,985	)		(1,311	)		(3	)		(1	)		(1,274	)		(5,574	)
Income (loss) from continuing operations before income taxes		35,879			7,394			4,920			(1,127	)		(10,470	)		36,596
Income tax expense (benefit)		22,829			9,253			—			—			(5,723	)		26,359
Income (loss) from continuing operations		13,050			(1,859	)		4,920			(1,127	)		(4,747	)		10,237
Loss from discontinued operations, net of tax		—			—			—			—			(15	)		(15	)
Net income (loss)	$	13,050		$	(1,859	)	$	4,920		$	(1,127	)	$	(4,762	)	$	10,222
Consolidated capital expenditures	$	5,064		$	20,097		$	16,656		$	—		$	36		$	41,852

	Three Months Ended June 30, 2022
(in thousands)	Gabon			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil and natural gas sales	$	110,985		$	—		$	—		$	110,985
Operating costs and expenses:
Production expense		25,360			175			(60	)		25,475
Exploration expense		67			—			—			67
Depreciation, depletion and amortization		8,173			—			18			8,191
General and administrative expense		565			110			2,859			3,534
Bad debt expense and other		571			—			—			571
Total operating costs and expenses		34,736			285			2,817			37,838
Other operating income (expense), net		—			—			—			—
Operating income		76,249			(285	)		(2,817	)		73,147
Other income (expense):
Derivative instruments loss, net		—			—			(9,542	)		(9,542	)
Interest (expense) income, net		(158	)		—			40			(118	)
Other (expense) income, net		(856	)		(1	)		(1,254	)		(2,111	)
Total other expense, net		(1,014	)		(1	)		(10,756	)		(11,771	)
Income from continuing operations before income taxes		75,235			(286	)		(13,573	)		61,376
Income tax (benefit) expense		36,423			1			9,828			46,252
Income from continuing operations		38,812			(287	)		(23,401	)		15,124
Loss from discontinued operations, net of tax		—			—			(20	)		(20	)
Net income	$	38,812		$	(287	)	$	(23,421	)	$	15,104
Consolidated capital expenditures (1)	$	38,102		$	—		$	67		$	38,169

	Six Months Ended June 30, 2022
(in thousands)	Gabon			Equatorial Guinea			Corporate and Other			Total
Revenues:
Crude oil and natural gas sales	$	179,641		$	—		$	—		$	179,641
Operating costs and expenses:
Production expense		43,441			394			—			43,835
Exploration expense		194			—			—			194
Depreciation, depletion and amortization		12,826			—			38			12,864
General and administrative expense		1,158			209			7,161			8,528
Credit losses and other		1,063			—			—			1,063
Total operating costs and expenses		58,682			603			7,199			66,484
Other operating income (expense), net		(5	)		—			—			(5	)
Operating income		120,954			(603	)		(7,199	)		113,152
Other income (expense):
Derivative instruments loss, net		—			—			(41,300	)		(41,300	)
Interest (expense) income, net		(164	)		—			43			(121	)
Other (expense) income, net		(1,494	)		(2	)		(1,311	)		(2,807	)
Total other expense, net		(1,658	)		(2	)		(42,568	)		(44,228	)
Income from continuing operations before income taxes		119,296			(605	)		(49,767	)		68,924
Income tax (benefit) expense		49,256			1			(7,633	)		41,624
Income from continuing operations		70,040			(606	)		(42,134	)		27,300
Loss from discontinued operations, net of tax		—			—			(32	)		(32	)
Net income	$	70,040		$	(606	)	$	(42,166	)	$	27,268
Consolidated capital expenditures (1)	$	69,882		$	—		$	67		$	69,949

Reconciliation of Assets from Segment to Consolidated [Table Text Block]

(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Corporate and Other		Total
Long-lived assets from continuing operations:
As of June 30, 2023	$	193,501	$	165,813	$	111,677	$	10,000	$	749	$	481,740
As of December 31, 2022 (1)		213,204	$	168,012	$	103,263	$	10,000	$	793	$	495,272

(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Corporate and Other		Total
Total assets from continuing operations:
As of June 30, 2023	$	384,554	$	270,653	$	118,604	$	11,144	$	44,058	$	829,013
As of December 31, 2022 (1)		395,393	$	293,640	$	110,071	$	10,861	$	45,676	$	855,641

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Note 5 - Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Weighted Average Number of Shares [Table Text Block]

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands)
Net income (loss) (numerator):
Income (loss) from continuing operations	$	6,754		$	15,124		$	10,237		$	27,300
Income from continuing operations attributable to unvested shares		(27	)		(229	)		(15	)		(381	)
Numerator for basic		6,727			14,895			10,222			26,919
Loss from continuing operations attributable to unvested shares		—			1			(41	)		2
Numerator for dilutive	$	6,727		$	14,896		$	10,181		$	26,921
Loss from discontinued operations, net of tax	$	(2	)	$	(20	)	$	(15	)	$	(32	)
Loss from discontinued operations attributable to unvested shares		—			—			—			—
Numerator for basic		(2	)		(20	)		(15	)		(32	)
(Income) loss from discontinued operations attributable to unvested shares		—			—			—			—
Numerator for dilutive	$	(2	)	$	(20	)	$	(15	)	$	(32	)
Net income (loss)	$	6,752		$	15,104		$	10,222		$	27,268
Net income attributable to unvested shares		(27	)		(229	)		(56	)		(381	)
Numerator for basic		6,725			14,875			10,166			26,887
Net (income) loss attributable to unvested shares		27			1			41			2
Numerator for dilutive	$	6,752		$	14,876		$	10,125		$	26,889
Weighted average shares (denominator):
Basic weighted average shares outstanding		106,965			58,925			107,175			58,814
Effect of dilutive securities		648			436			875			464
Diluted weighted average shares outstanding		107,613			59,361			108,050			59,278
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		431			251			238			154

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Note 6 - Revenue (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Disaggregation of Revenue [Table Text Block]

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Revenues from customer contracts:	(in thousands)
Sales under the COSPA or COSMA	$	87,478		$	125,143		$	130,079		$	201,629
Other items reported in revenue not associated with customer contracts:
Carried interest recoupment		2,212			2,371			2,212			3,483
Royalties		(11,766	)		(16,529	)		(17,630	)		(25,471	)
Net revenues	$	77,924		$	110,985		$	114,661		$	179,641

	Three Months Ended June 30,			Six Months Ended June 30,
	2023			2023
Revenues from customer contracts:	(in thousands)
Gross sales	$	50,201		$	104,822
Royalties		(28,892	)		(48,232	)
Selling costs		(1	)		(498	)
Net revenues	$	21,308		$	56,092

	Three Months Ended June 30,			Six Months Ended June 30,
	2023			2023
Revenues from customer contracts:	(in thousands)
Oil revenue	$	8,325		$	14,979
Gas revenue		703			1,661
NGL revenue		1,885			4,348
Royalties		(905	)		(2,098	)
Net revenues	$	10,008		$	18,890

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Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Property, Plant and Equipment [Table Text Block]

	As of June 30, 2023			As of December 31, 2022
	(in thousands)
Crude oil, natural gas and NGLs properties and equipment - successful efforts method:
Wells, platforms and other production facilities	$	1,446,801		$	1,406,888
Work-in-progress		—			—
Undeveloped acreage		54,346			56,251
Equipment and other		43,835			38,796
		1,544,982			1,501,935
Accumulated depreciation, depletion, amortization and impairment		(1,063,242	)		(1,006,663	)
Net crude oil, natural gas and NGLs properties, equipment and other	$	481,740		$	495,272

Collaborative Arrangement and Arrangement Other than Collaborative [Table Text Block]

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	%

Crude Oil Production [Table Text Block]

*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

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Note 8 - Derivatives and Fair Value (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

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

Schedule of Derivative Instruments [Table Text Block]

		Three Months Ended June 30,						Six Months Ended June 30,
Derivative Item	Statements of Operations Line	2023			2022			2023			2022
		(in thousands)						(in thousands)
Commodity derivatives	Cash settlements paid on matured derivative contracts, net	$	(4	)	$	(21,059	)	$	(63	)	$	(33,559	)
	Unrealized gain (loss)		35			11,517			115			(7,741	)
	Derivative instruments gain (loss), net	$	31		$	(9,542	)	$	52		$	(41,300	)

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Note 9 - Accrued Liabilities and Other (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]

	As of June 30, 2023		As of December 31, 2022
	(in thousands)
Accrued accounts payable invoices	$	21,480	$	28,360
Gabon DMO, PID and PIH obligations		12,782		10,509
Capital expenditures		19,770		26,618
Stock appreciation rights – current portion		32		570
Accrued wages and other compensation		2,726		8,161
ARO Obligation		5,729		306
Egypt modernization payments		9,373		9,933
Excess cost oil payable		8,099		—
Other		4,113		6,935
Total accrued liabilities and other	$	84,104	$	91,392

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Note 10 - Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Other Commitments [Table Text Block]

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	$	4.94		303,969	$	21,003,245
May 1, 2023 - May 31, 2023		362,843	$	4.14		362,843	$	19,502,740
June 1, 2023 - June 30, 2023		494,164	$	4.05		494,164	$	17,504,007
Total		1,160,976				1,160,976

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
July 1, 2023 - July 31, 2023		505,720		$3.96		505,720		$15,504,180
August 1, 2023 - August 4, 2023		98,411		$4.29		98,411		$15,082,133
Total		604,131				604,131

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Note 12 - Leases (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Lease, Cost [Table Text Block]

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Lease cost:	(in thousands)
Finance lease cost (1)	$	4,115	$	98	$	8,480	$	164
Operating lease cost		339		4,265		922		8,461
Short-term lease cost (2)		1,660		199		3,020		1,213
Variable lease cost (3)		—		1,909		—		3,247
Total lease expense		6,114		6,471		12,422		13,085
Lease costs capitalized		7		651		55		1,423
Total lease costs	$	6,121	$	7,122	$	12,477	$	14,508

	Six Months Ended June 30,
	2023			2022
Other information:
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash flows attributable to finance leases (in thousands)	$	3,379		$	26
Weighted-average remaining lease term (in years)		8.96			5.17
Weighted-average discount rate		8.11	%		3.54	%
Operating cash flows attributable to operating leases (in thousands)	$	423		$	12,816
Weighted-average remaining lease term (in years)		0.95			0.70
Weighted-average discount rate		10.33	%		5.62	%

Summary of Lease Costs in Consolidated Statements of Operations [Table Text Block]

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(in thousands)
Finance lease cost	$	2,376	$	57	$	5,001	$	96
Production expense		1,208		3,720		2,494		7,558
General and administrative expense		52		47		98		63
Lease costs billed to the joint venture owners		2,481		2,884		4,849		5,886
Total lease expense		6,117		6,708		12,442		13,603
Lease costs capitalized		4		414		35		905
Total lease costs	$	6,121	$	7,122	$	12,477	$	14,508

Lessee, Operating and Finance Lease Liability, Maturity [Table Text Block]

	Operating Leases		Finance Leases
Year	(in thousands)
2023	$	1,173	$	7,287
2024		672		14,448
2025		32		16,202
2026		—		16,478
2027		—		15,023
Thereafter		—		51,527
		1,877		120,965
Less: imputed interest		80		33,425
Total lease liabilities	$	1,797	$	87,540

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Note 13 - Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Change in Asset Retirement Obligation [Table Text Block]

(in thousands)	As of June 30, 2023			As of December 31, 2022
Beginning balance	$	42,001		$	40,694
Accretion		1,118			1,958
Additions		—			6,134
Revisions		5,726			(43	)
Settlements		(374	)		(6,577	)
Foreign currency gain (loss)		216			(165	)
Ending balance	$	48,687		$	42,001

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Note 14 - Shareholders' Equity (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Stockholders Equity [Table Text Block]

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	$	4.94		303,969	$	21,003,245
May 1, 2023 - May 31, 2023		362,843	$	4.14		362,843	$	19,502,740
June 1, 2023 - June 30, 2023		494,164	$	4.05		494,164	$	17,504,007
Total		1,160,976				1,160,976

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Note 15 - Stock-based Compensation and Other Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Share-Based Payment Arrangement, Expensed and Capitalized, Amount [Table Text Block]

	Three Months Ended June 30,					Six Months Ended June 30,
	2023			2022		2023			2022
	(in thousands)
Stock-based compensation - equity awards	$	706		$	615	$	1,381		$	1,019
Stock-based compensation - liability awards		(101	)		227		(127	)		1,245
Total stock-based compensation	$	605		$	842	$	1,254		$	2,264

Schedule of Share-Based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

	Six Months Ended June 30,
	2023			2022
Weighted average exercise price - ($/share)	$	4.19		$	6.41
Expected life in years		6.4			6.0
Average expected volatility		68	%		72	%
Risk-free interest rate		3.73	%		1.98	%
Expected dividend yield		5.97	%		2.30	%
Weighted average grant date fair value - ($/share)	$	2.29		$	2.84

Share-Based Payment Arrangement, Option, Activity [Table Text Block]

	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		$	3.95
Granted		335			4.19
Exercised		(74	)		(1.68	)
Unvested shares forfeited		—			—
Vested shares expired		—			—
Outstanding at June 30, 2023		705		$	4.30			8.95	$	280
Exercisable at June 30, 2023		211		$	3.34			7.70	$	262

	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		(164	)		(1.56	)
Unvested shares forfeited		—			—
Vested shares expired		—			—
Outstanding at June 30, 2023		223		$	2.07			0.73	$	376
Exercisable at June 30, 2023		223		$	2.07			0.73	$	376

Nonvested Restricted Stock Shares Activity [Table Text Block]

	Restricted Stock			Weighted Average Grant Date Fair Value
	(in thousands)
Non-vested shares outstanding at January 1, 2023		665		$	4.59
Awards granted		797			4.19
Awards vested		(354	)		3.92
Awards forfeited		(12	)		5.73
Non-vested shares outstanding at June 30, 2023		1,096		$	4.51

	Restricted Stock			Weighted Average Conversion Date Fair Value
	(in thousands)
Non-vested shares outstanding at January 1, 2023		383		$	4.27
Awards granted		183			4.19
Awards vested		(259	)		4.27
Awards forfeited		(23	)		4.27
Non-vested shares outstanding at June 30, 2023		284		$	4.22

Share-Based Payment Arrangement, Performance Shares, Activity [Table Text Block]

	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		(514	)		4.27
Awards forfeited		(36	)		4.27
Non-vested shares outstanding at June 30, 2023		140		$	4.27

Share-Based Payment Arrangement, Stock Appreciation Right, Activity [Table Text Block]

	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 June 30, 2023		139		$	2.33		0.64	$	198
Exercisable at June 30, 2023		139		$	2.33		0.64	$	198

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Note 16 - Income Taxes (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

	Three Months Ended June 30,					Six Months Ended June 30,
	2023			2022		2023		2022
U.S. Federal:	(in thousands)
Current	$	—		$	—	$	—	$	—
Deferred		871			2,617		1,457		(9,869	)
Foreign:
Current		12,401			20,402		24,701		26,093
Deferred		(1,684	)		23,233		201		25,400
Total	$	11,588		$	46,252	$	26,359	$	41,624

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Note 17 - Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2023

Notes Tables

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

	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
Accumulated other comprehensive income (loss) before reclassifications		2,006
Balance at June 30, 2023	$	3,060

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Note 1 - Organization and Accounting Policies (Details Textual) $ in Thousands				1 Months Ended		3 Months Ended								6 Months Ended		12 Months Ended
	Jan. 12, 2023 USD ($)	Jan. 01, 2023 USD ($)	Jan. 19, 2022 USD ($)	Jul. 31, 2023 USD ($)	Mar. 31, 2023 USD ($)	Jun. 30, 2023 USD ($)	Jun. 30, 2023 USD ($) $ / item	Jun. 30, 2023 USD ($) $ / bbl	Mar. 31, 2023 USD ($) $ / bbl	Dec. 31, 2022 USD ($) $ / bbl	Sep. 30, 2022 $ / bbl	Jun. 30, 2022 USD ($) $ / bbl	Mar. 31, 2022 USD ($) $ / bbl	Jun. 30, 2023 USD ($)	Jun. 30, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Oct. 13, 2022 USD ($)
Oil and Gas, Average Sale Price (in USD per Per Share)							78	77.99	81.07	88.72	100.71	113.84	100.87
Restricted Cash						$ 100	$ 100	$ 100						$ 100
Payments for Abandonment Funding									$ 15,600								$ 0
Abandonment Funding Payment Due										$ 5,800
Reestablishment of Currency Denominated Account	$ 37,300
Abandonment Funding Payment Approved					$ 26,600				26,600
Abandonment Funding Payment Approved, Attributable to Company					15,600				15,600
Payment Received for Abandonment					15,600
Value Added Tax Receivable						15,800	15,800	15,800		13,900				15,800
Accounts Receivable, Credit Loss Expense (Reversal)						680						$ 571		1,615	$ 1,063
Provision for Doubtful Accounts Transferred						200			300
Accounts Receivable, Allowance for Credit Loss					12,832	13,519	13,519	13,519	12,832	8,704		$ 6,389	$ 6,135	13,519	$ 6,389	$ 5,741
Prepayments for Fixed Assets						2,500	2,500	2,500						2,500
Prepaid Insurance						1,500	1,500	1,500						1,500
Other Prepaid Expense, Current						$ 5,100	$ 5,100	$ 5,100						$ 5,100
Office Equipment [Member] | Maximum [Member]
Property, Plant and Equipment, Useful Life (Year)						5 years	5 years	5 years						5 years
Leasehold Improvements [Member] | Maximum [Member]
Property, Plant and Equipment, Useful Life (Year)						7 years	7 years	7 years						7 years
Leasehold Improvements [Member] | Minimum [Member]
Property, Plant and Equipment, Useful Life (Year)						5 years	5 years	5 years						5 years
GABON
Prepaid Royalties						$ 2,700	$ 2,700	$ 2,700						$ 2,700
EGYPT
Prepaid Fuel						4,000	4,000	4,000						4,000
Advances to Contractors						1,900	1,900	1,900						1,900
Prepaid Payroll						400	400	400						400
Tax Administration of Gabon [Member]
Provision for Value Added Tax						500								1,100
Block P Offshore Equatorial Guinea [Member]
Accounts Receivable, Allowance for Credit Loss						500	$ 500	$ 500						$ 500
Oil Delivery [Member]
Accounts Receivable, Credit Loss Expense (Reversal)						$ 0			400
Accounting Standards Update 2016-13 [Member] | Cumulative Effect, Period of Adoption, Adjustment [Member]
Other Receivables		$ 18,200
Accounts Receivable, Credit Loss Expense (Reversal)		3,100
Accounts Receivable, Allowance for Credit Loss		$ 3,100			$ (0)				$ (0)	$ 3,120			$ (0)			$ (0)
Communaute Financiere Africaine BEAC, Francs
Foreign Currency Exchange Rate, Translation						602.552	602.552	602.552		612.6				602.552
Canada, Dollars
Foreign Currency Exchange Rate, Translation						0.755	0.755	0.755		0.738				0.755
Vaalco Energy Inc. and Other Etame Marin Block Owners [Member]
Value Added Tax Receivable						$ 24,300	$ 24,300	$ 24,300		$ 21,800				$ 24,300
TransGlobe [Member]
Proceeds From Other Receivables										$ 17,200
Merged Concession Agreement, Development Term (Year)			15 years
Merged Concession Agreement, Extension Term (Year)			5 years
Other Receivables			$ 67,500			50,300	50,300	50,300						50,300				$ 67,500
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member]
Accounts Payable, Other, Current						19,700	19,700	19,700						19,700
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Subsequent Event [Member]
Proceeds From Other Receivables				$ 1,900
Other, Net [Member]
Accounts Receivable, after Allowance for Credit Loss						$ 19,700	$ 19,700	$ 19,700						$ 19,700
Purchase Commitment [Member]
Number of Contracts Entered Into																2

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Note 1 - Organization and Accounting Policies - Average Brent Crude Oil Price (Details)	3 Months Ended
	Jun. 30, 2023 $ / item	Jun. 30, 2023 $ / bbl	Mar. 31, 2023 $ / bbl	Dec. 31, 2022 $ / bbl	Sep. 30, 2022 $ / bbl	Jun. 30, 2022 $ / bbl	Mar. 31, 2022 $ / bbl
Average sales price (in USD per Barrel of Oil)	78	77.99	81.07	88.72	100.71	113.84	100.87

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Note 1 - Organization and Accounting Policies - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Jun. 30, 2023	Dec. 31, 2022	Jun. 30, 2022
Cash and cash equivalents	$ 46,186		$ 53,062
Restricted cash	113	$ 222	216
Restricted cash - non-current	1,779	1,763	1,752
Abandonment funding	6,268	$ 20,586	20,091
Total cash, cash equivalents and restricted cash	$ 54,346		$ 75,121

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Note 1 - Organization and Accounting Policies - Analysis of Change in Allowance for Bad Debt (Details) - USD ($) $ in Thousands		3 Months Ended			6 Months Ended
	Jan. 01, 2023	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Balance at beginning of period	$ (8,704)	$ (12,832)	$ (8,704)	$ (6,135)	$ (8,704)	$ (5,741)
Credit loss charges and other, net of receipts		(680)		(571)	(1,615)	(1,063)
Foreign currency gain (loss)		(7)		317	(80)	415
Balance at end of period		(13,519)	(12,832)	(6,389)	(13,519)	(6,389)
Accounting Standards Update 2016-13 [Member] | Cumulative Effect, Period of Adoption, Adjustment [Member]
Balance at beginning of period	(3,120)	$ 0	(3,120)	$ 0	$ (3,120)	$ 0
Credit loss charges and other, net of receipts	(3,100)
Balance at end of period	$ (3,100)		$ 0

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Note 1 - Organization and Accounting Policies - Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2023	Dec. 31, 2022
Assets, Fair Value Disclosure	$ 158	$ 102
Liabilities, Fair Value Disclosure	196	556
Assets, Fair Value Disclosure	158	102
Liabilities, Fair Value Disclosure	196	556
Prepayments and Other [Member]
Derivative asset	158	102
Accrued Liabilities and Other [Member]
SARs liability	196	556
Fair Value, Inputs, Level 1 [Member]
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	0
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 1 [Member] | Prepayments and Other [Member]
Derivative asset	0	0
Fair Value, Inputs, Level 1 [Member] | Accrued Liabilities and Other [Member]
SARs liability	0	0
Fair Value, Inputs, Level 2 [Member]
Assets, Fair Value Disclosure	158	102
Liabilities, Fair Value Disclosure	196	556
Assets, Fair Value Disclosure	158	102
Liabilities, Fair Value Disclosure	196	556
Fair Value, Inputs, Level 2 [Member] | Prepayments and Other [Member]
Derivative asset	158	102
Fair Value, Inputs, Level 2 [Member] | Accrued Liabilities and Other [Member]
SARs liability	196	556
Fair Value, Inputs, Level 3 [Member]
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	0
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member] | Prepayments and Other [Member]
Derivative asset	0	0
Fair Value, Inputs, Level 3 [Member] | Accrued Liabilities and Other [Member]
SARs liability	$ 0	$ 0

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Note 2 - New Accounting Standards (Details Textual) - USD ($) $ in Thousands	Jun. 30, 2023	Mar. 31, 2023	Jan. 01, 2023	Dec. 31, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss	$ 13,519	$ 12,832		$ 8,704	$ 6,389	$ 6,135	$ 5,741
Accounting Standards Update 2016-13 [Member] | Cumulative Effect, Period of Adoption, Adjustment [Member]
Accounts Receivable, Allowance for Credit Loss		$ (0)	$ 3,100	$ 3,120		$ (0)	$ (0)

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Note 3 - Acquisitions and Dispositions (Details Textual) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
	Oct. 13, 2022 USD ($) $ / shares shares	Jun. 30, 2023 USD ($) $ / shares	Mar. 31, 2023 USD ($)	Jun. 30, 2023 USD ($) $ / shares	Dec. 31, 2022 $ / shares	Nov. 30, 2006
Common Stock, Par or Stated Value Per Share (in dollars per share) | $ / shares	$ 0.10	$ 0.10		$ 0.10	$ 0.10
Block 5 PSA [Member]
Equity Method Investment, Ownership Percentage						40.00%
Equity Method Investment, Additional Working Interest Percentage						10.00%
Excluded From ProForma [Member] | TransGlobe [Member]
Asset Impairment Charges			$ 26.0
VAALCO Energy [Member] | VAALCO Stockholders [Member]
Estimated Ownership to Be Received, Percent	54.50%
VAALCO Energy [Member] | TransGlobe Shareholders [Member]
Estimated Ownership to Be Received, Percent	45.50%
TransGlobe [Member]
Business Acquisition, Exchange Ratio	0.6727
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares (in shares) | shares	49.3
Business Combination, Bargain Purchase, Increase (Decrease) of Gain Recognized, Amount				$ 1.4
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		$ 31.3		75.0
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual		8.0		1.7
Business Combination, Bargain Purchase, Gain Recognized, Amount	$ 10.8		$ 9.4
TransGlobe [Member] | Foreign Tax Authority [Member] | Egyptian Tax Authority [Member]
Business Combination, Deferred Tax Liability Assumed		$ 1.4		$ 1.4

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Note 3 - Acquisitions and Dispositions - Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - TransGlobe [Member] $ in Thousands	Oct. 13, 2022 USD ($)
Common stock issued to TransGlobe shareholders	$ 274,145
Cash	36,686
Wells, platforms and other production facilities	243,669
Equipment and other	2,099
Undeveloped acreage	30,216
Accounts receivable - trade	48,068
Accounts receivable - other	50,275
Accounts with joint venture owners	68
Right of use operating leases	1,609
Right of use financing leases	204
Prepayment and other	7,627
Asset retirement obligations	(6,134)
Accounts payable	(10,223)
Accrued liabilities and other	(50,128)
Operating lease liabilities - current portion	(961)
Financing lease liabilities - current portion	(125)
Operating lease liabilities - net of current portion	(688)
Financing lease liabilities - net of current portion	(21)
Deferred tax liabilities	(40,964)
Other long-term liabilities	(26,313)
Bargain purchase gain	(10,819)
Total purchase price	274,145
Cumulative Effect, Period of Adoption, Adjusted Balance [Member]
Common stock issued to TransGlobe shareholders	274,145
Cash	36,686
Wells, platforms and other production facilities	243,669
Equipment and other	2,099
Undeveloped acreage	30,216
Accounts receivable - trade	48,068
Accounts receivable - other	50,275
Accounts with joint venture owners	68
Right of use operating leases	1,609
Right of use financing leases	204
Prepayment and other	7,627
Asset retirement obligations	(6,134)
Accounts payable	(10,223)
Accrued liabilities and other	(50,128)
Operating lease liabilities - current portion	(961)
Financing lease liabilities - current portion	(125)
Operating lease liabilities - net of current portion	(688)
Financing lease liabilities - net of current portion	(21)
Deferred tax liabilities	(42,376)
Other long-term liabilities	(26,313)
Bargain purchase gain	(9,407)
Total purchase price	274,145
Cumulative Effect, Period of Adoption, Adjustment [Member]
Deferred tax liabilities	(1,412)
Bargain purchase gain	$ 1,412

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Note 3 - Acquisition and Dispositions - Unaudited Proforma Results (Details) - Etame Marine Block [Member] - USD ($) $ / shares in Units, shares in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2022		Jun. 30, 2022
Crude oil, natural gas and natural gas liquids sales	[1]	$ 183,665		$ 304,792
Operating income		110,091,000	[2]	171,518,000	[3]
Net income		$ 41,818,000	[2]	$ 72,857,000	[4]
Basic net income per share: (in dollars per share)		$ 0.39		$ 0.67
Basic weighted average shares outstanding (in shares)		108,232		108,121
Diluted net income per share: (in dollars per share)		$ 0.38		$ 0.67
Diluted weighted average shares outstanding (in shares)		108,668		108,585

[1] 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.

[2] The unaudited pro forma operating income for the three months ended June 30, 2022 reclassifies depreciation expense, 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.

[3] The unaudited pro forma operating income for the six months ended June 30, 2022 removes the $26.0 million impairment reversal recorded by TransGlobe in 2022, reclassifies depreciation expense, 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.

[4] The unaudited pro forma net income for the six months ended June 30, 2022 reclassifies interest expense, for certain leases identified as operating leases, as production expense.

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Note 4 - Segment Information (Details Textual) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022	May 16, 2022
Customer Concentration Risk [Member] | Revenue Benchmark [Member] | Glencore [Member] | Oil and Gas [Member]
Concentration Risk, Percentage	100.00%			100.00%
Customer Concentration Risk [Member] | Revenue Benchmark [Member] | Exxon [Member] | Oil and Gas [Member]
Concentration Risk, Percentage			100.00%		100.00%
Customer Concentration Risk [Member] | Revenue Benchmark [Member] | Plains Midstream Canada [Member] | CANADA
Concentration Risk, Percentage	50.90%			50.90%
Customer Concentration Risk [Member] | Revenue Benchmark [Member] | Altagas [Member] | CANADA
Concentration Risk, Percentage	19.10%			19.10%
Customer Concentration Risk [Member] | Revenue Benchmark [Member] | PetroGas Energy [Member] | CANADA
Concentration Risk, Percentage	18.60%			18.60%
Geographic Concentration Risk [Member] | Revenue Benchmark [Member] | EGPC [Member] | Oil and Gas [Member] | EGYPT
Concentration Risk, Percentage	100.00%
Geographic Concentration Risk [Member] | Revenue Benchmark [Member] | Mercuria [Member] | Oil and Gas [Member] | EGYPT
Concentration Risk, Percentage		100.00%
Revolving Credit Facility [Member]
Line of Credit Facility, Maximum Borrowing Capacity						$ 50

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Note 4 - Segment Information - Segment Activity of Continuing Operations (Details) - USD ($) $ in Thousands		3 Months Ended					6 Months Ended
		Jun. 30, 2023		Mar. 31, 2023	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2023		Jun. 30, 2022
Crude oil, natural gas and natural gas liquids sales		$ 109,240			$ 110,985		$ 189,643		$ 179,641
Production expense		38,604			25,475		66,804		43,835
FPSO Demobilization - Norms Waste Disposal		5,647			0		5,647		0
Exploration expense		57			67		65		194
Depreciation, depletion and amortization		38,003			8,191		62,420		12,864
General and administrative expense		5,395			3,534		10,619		8,528
Accounts Receivable, Credit Loss Expense (Reversal)		680			571		1,615		1,063
Total operating costs and expenses		88,386			37,838		147,170		66,484
Other operating expense, net		(303)			0		(303)		(5)
Operating income		20,551			73,147		42,170		113,152
Derivative instruments gain (loss), net		31			(9,542)		52		(41,300)
Interest expense, net		(1,703)			(118)		(3,949)		(121)
Other expense, net		(537)			(2,111)		(1,677)		(2,807)
Total other expense, net		(2,209)			(11,771)		(5,574)		(44,228)
Income (loss) from continuing operations before income taxes		18,342			61,376		36,596		68,924
Income tax (benefit) expense		11,588			46,252		26,359		41,624
Income (loss) from continuing operations		6,754			15,124		10,237		27,300
Loss from discontinued operations, net of tax		(2)			(20)		15		32
Net income		6,752		$ 3,470	15,104	$ 12,164	10,222		27,268
Consolidated capital expenditures		16,427	[1]		38,169		41,852	[1]	69,949
Loss from discontinued operations, net of tax		2			20		(15)		(32)
Crude oil and natural gas sales		109,240			110,985		189,643		179,641
Production expense		38,604			25,475		66,804		43,835
Exploration expense		57			67		65		194
General and administrative expense		5,395			3,534		10,619		8,528
Total operating costs and expenses		88,386			37,838		147,170		66,484
Derivative instruments loss, net		31			(9,542)		52		(41,300)
Interest (expense) income, net		(1,703)			(118)		(3,949)		(121)
Other (expense) income, net		(537)			(2,111)		(1,677)		(2,807)
Total other expense, net		(2,209)			(11,771)		(5,574)		(44,228)
Income from continuing operations before income taxes		18,342			61,376		36,596		68,924
Income from continuing operations		6,754			15,124		10,237		27,300
Loss from discontinued operations, net of tax		(2)			(20)		15		32
Net income		6,752		$ 3,470	15,104	$ 12,164	10,222		27,268
Consolidated capital expenditures (1)		16,427	[1]		38,169		41,852	[1]	69,949
Other operating income (expense), net		(303)			0		(303)		(5)
Loss from discontinued operations, net of tax		2			20		(15)		(32)
Corporate, Non-Segment [Member]
Crude oil, natural gas and natural gas liquids sales		0			0		0		0
Production expense		(57)			(60)		2		0
FPSO Demobilization - Norms Waste Disposal		0					0
Exploration expense		0			0		0		0
Depreciation, depletion and amortization		42			18		108		38
General and administrative expense		4,788			2,859		9,086		7,161
Accounts Receivable, Credit Loss Expense (Reversal)		0			0		0		0
Total operating costs and expenses		4,773			2,817		9,196		7,199
Other operating expense, net		0			0		0		0
Operating income		(4,773)			(2,817)		(9,196)		(7,199)
Derivative instruments gain (loss), net		31			(9,542)		52		(41,300)
Interest expense, net		176			40		249		43
Other expense, net		81			(1,254)		(1,575)		(1,311)
Total other expense, net		288			(10,756)		(1,274)		(42,568)
Income (loss) from continuing operations before income taxes		(4,485)			(13,573)		(10,470)		(49,767)
Income tax (benefit) expense		(8,924)			9,828		(5,723)		(7,633)
Income (loss) from continuing operations		4,439			(23,401)		(4,747)		(42,134)
Loss from discontinued operations, net of tax		(2)			(20)		15		32
Net income		4,437			(23,421)		(4,762)		(42,166)
Consolidated capital expenditures		36	[1]		67		36	[1]	67
Loss from discontinued operations, net of tax		2			20		(15)		(32)
Crude oil and natural gas sales		0			0		0		0
Production expense		(57)			(60)		2		0
Exploration expense		0			0		0		0
General and administrative expense		4,788			2,859		9,086		7,161
Total operating costs and expenses		4,773			2,817		9,196		7,199
Derivative instruments loss, net		31			(9,542)		52		(41,300)
Interest (expense) income, net		176			40		249		43
Other (expense) income, net		81			(1,254)		(1,575)		(1,311)
Total other expense, net		288			(10,756)		(1,274)		(42,568)
Income from continuing operations before income taxes		(4,485)			(13,573)		(10,470)		(49,767)
Income from continuing operations		4,439			(23,401)		(4,747)		(42,134)
Loss from discontinued operations, net of tax		(2)			(20)		15		32
Net income		4,437			(23,421)		(4,762)		(42,166)
Consolidated capital expenditures (1)		36	[1]		67		36	[1]	67
Other operating income (expense), net		0			0		0		0
Loss from discontinued operations, net of tax		2			20		(15)		(32)
Gabon Segment [Member] | Operating Segments [Member]
Crude oil, natural gas and natural gas liquids sales		77,924			110,985		114,661		179,641
Production expense		23,931			25,360		38,346		43,441
FPSO Demobilization - Norms Waste Disposal		5,647					5,647
Exploration expense		43			67		51		194
Depreciation, depletion and amortization		19,457			8,173		29,302		12,826
General and administrative expense		318			565		936		1,158
Accounts Receivable, Credit Loss Expense (Reversal)		518			571		1,453		1,063
Total operating costs and expenses		49,914			34,736		75,735		58,682
Other operating expense, net		(62)			0		(62)		(5)
Operating income		27,948			76,249		38,864		120,954
Derivative instruments gain (loss), net		0			0		0		0
Interest expense, net		(1,376)			(158)		(2,883)		(164)
Other expense, net		(619)			(856)		(102)		(1,494)
Total other expense, net		(1,995)			(1,014)		(2,985)		(1,658)
Income (loss) from continuing operations before income taxes		25,953			75,235		35,879		119,296
Income tax (benefit) expense		16,251			36,423		22,829		49,256
Income (loss) from continuing operations		9,702			38,812		13,050		70,040
Loss from discontinued operations, net of tax		0			0		(0)		(0)
Net income		9,702			38,812		13,050		70,040
Consolidated capital expenditures		1,375	[1]		38,102		5,064	[1]	69,882
Loss from discontinued operations, net of tax		0			0		0		0
Crude oil and natural gas sales		77,924			110,985		114,661		179,641
Production expense		23,931			25,360		38,346		43,441
Exploration expense		43			67		51		194
General and administrative expense		318			565		936		1,158
Total operating costs and expenses		49,914			34,736		75,735		58,682
Derivative instruments loss, net		0			0		0		0
Interest (expense) income, net		(1,376)			(158)		(2,883)		(164)
Other (expense) income, net		(619)			(856)		(102)		(1,494)
Total other expense, net		(1,995)			(1,014)		(2,985)		(1,658)
Income from continuing operations before income taxes		25,953			75,235		35,879		119,296
Income from continuing operations		9,702			38,812		13,050		70,040
Loss from discontinued operations, net of tax		0			0		(0)		(0)
Net income		9,702			38,812		13,050		70,040
Consolidated capital expenditures (1)		1,375	[1]		38,102		5,064	[1]	69,882
Other operating income (expense), net		(62)			0		(62)		(5)
Loss from discontinued operations, net of tax		0			0		0		0
Egypt [Member] | Operating Segments [Member]
Crude oil, natural gas and natural gas liquids sales		21,308					56,092
Production expense		11,089					22,199
FPSO Demobilization - Norms Waste Disposal		0					0
Exploration expense		14					14
Depreciation, depletion and amortization		13,757					24,552
General and administrative expense		202					381
Accounts Receivable, Credit Loss Expense (Reversal)		0					0
Total operating costs and expenses		25,062					47,146
Other operating expense, net		(241)					(241)
Operating income		(3,995)					8,705
Derivative instruments gain (loss), net		0					0
Interest expense, net		(503)					(1,311)
Other expense, net		0					0
Total other expense, net		(503)					(1,311)
Income (loss) from continuing operations before income taxes		(4,498)					7,394
Income tax (benefit) expense		4,261					9,253
Income (loss) from continuing operations		(8,759)					(1,859)
Loss from discontinued operations, net of tax		0					(0)
Net income		(8,759)					(1,859)
Consolidated capital expenditures	[1]	8,526					20,097
Loss from discontinued operations, net of tax		0					0
Crude oil and natural gas sales		21,308					56,092
Production expense		11,089					22,199
Exploration expense		14					14
General and administrative expense		202					381
Total operating costs and expenses		25,062					47,146
Derivative instruments loss, net		0					0
Interest (expense) income, net		(503)					(1,311)
Other (expense) income, net		0					0
Total other expense, net		(503)					(1,311)
Income from continuing operations before income taxes		(4,498)					7,394
Income from continuing operations		(8,759)					(1,859)
Loss from discontinued operations, net of tax		0					(0)
Net income		(8,759)					(1,859)
Consolidated capital expenditures (1)	[1]	8,526					20,097
Other operating income (expense), net		(241)					(241)
Loss from discontinued operations, net of tax		0					0
Canada [Member] | Operating Segments [Member]
Crude oil, natural gas and natural gas liquids sales		10,008					18,890
Production expense		3,255					5,509
FPSO Demobilization - Norms Waste Disposal		0					0
Exploration expense		0					0
Depreciation, depletion and amortization		4,747					8,458
General and administrative expense		0					0
Accounts Receivable, Credit Loss Expense (Reversal)		0					0
Total operating costs and expenses		8,002					13,967
Other operating expense, net		0					0
Operating income		2,006					4,923
Derivative instruments gain (loss), net		0					0
Interest expense, net		0					(4)
Other expense, net		1					1
Total other expense, net		1					(3)
Income (loss) from continuing operations before income taxes		2,007					4,920
Income tax (benefit) expense		0					0
Income (loss) from continuing operations		2,007					4,920
Loss from discontinued operations, net of tax		0					(0)
Net income		2,007					4,920
Consolidated capital expenditures	[1]	6,491					16,656
Loss from discontinued operations, net of tax		0					0
Crude oil and natural gas sales		10,008					18,890
Production expense		3,255					5,509
Exploration expense		0					0
General and administrative expense		0					0
Total operating costs and expenses		8,002					13,967
Derivative instruments loss, net		0					0
Interest (expense) income, net		0					(4)
Other (expense) income, net		1					1
Total other expense, net		1					(3)
Income from continuing operations before income taxes		2,007					4,920
Income from continuing operations		2,007					4,920
Loss from discontinued operations, net of tax		0					(0)
Net income		2,007					4,920
Consolidated capital expenditures (1)	[1]	6,491					16,656
Other operating income (expense), net		0					0
Loss from discontinued operations, net of tax		0					0
Equatorial Guinea Segment [Member] | Operating Segments [Member]
Crude oil, natural gas and natural gas liquids sales		0			0		0		0
Production expense		386			175		748		394
FPSO Demobilization - Norms Waste Disposal		0					0
Exploration expense		0			0		0		0
Depreciation, depletion and amortization		0			0		0		0
General and administrative expense		87			110		216		209
Accounts Receivable, Credit Loss Expense (Reversal)		162			0		162		0
Total operating costs and expenses		635			285		1,126		603
Other operating expense, net		0			0		0		0
Operating income		(635)			(285)		(1,126)		(603)
Derivative instruments gain (loss), net		0			0		0		0
Interest expense, net		0			0		0		0
Other expense, net		0			(1)		(1)		(2)
Total other expense, net		0			(1)		(1)		(2)
Income (loss) from continuing operations before income taxes		(635)			(286)		(1,127)		(605)
Income tax (benefit) expense		0			1		0		1
Income (loss) from continuing operations		(635)			(287)		(1,127)		(606)
Loss from discontinued operations, net of tax		0			0		(0)		(0)
Net income		(635)			(287)		(1,127)		(606)
Consolidated capital expenditures		0	[1]		0		0	[1]	0
Loss from discontinued operations, net of tax		0			0		0		0
Crude oil and natural gas sales		0			0		0		0
Production expense		386			175		748		394
Exploration expense		0			0		0		0
General and administrative expense		87			110		216		209
Total operating costs and expenses		635			285		1,126		603
Derivative instruments loss, net		0			0		0		0
Interest (expense) income, net		0			0		0		0
Other (expense) income, net		0			(1)		(1)		(2)
Total other expense, net		0			(1)		(1)		(2)
Income from continuing operations before income taxes		(635)			(286)		(1,127)		(605)
Income from continuing operations		(635)			(287)		(1,127)		(606)
Loss from discontinued operations, net of tax		0			0		(0)		(0)
Net income		(635)			(287)		(1,127)		(606)
Consolidated capital expenditures (1)		0	[1]		0		0	[1]	0
Other operating income (expense), net		0			0		0		0
Loss from discontinued operations, net of tax		$ 0			$ 0		$ 0		$ 0

[1] Excludes assets acquired in the TransGlobe acquisition.

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Note 4 - Segment Information - Assets from Continuing Operations (Details) - USD ($) $ in Thousands	Jun. 30, 2023		Dec. 31, 2022	[2]
Long-lived assets from continuing operations	$ 481,740	[1]	$ 495,272
Total assets from continuing operations	829,013	[3]	855,641
Operating Segments [Member] | Gabon Segment [Member]
Long-lived assets from continuing operations	193,501	[1]	213,204
Total assets from continuing operations	384,554	[3]	395,393
Operating Segments [Member] | Egypt [Member]
Long-lived assets from continuing operations	165,813	[1]	168,012
Total assets from continuing operations	270,653	[3]	293,640
Operating Segments [Member] | Canada [Member]
Long-lived assets from continuing operations	111,677	[1]	103,263
Total assets from continuing operations	118,604	[3]	110,071
Operating Segments [Member] | Equatorial Guinea Segment [Member]
Long-lived assets from continuing operations	10,000	[1]	10,000
Total assets from continuing operations	11,144	[3]	10,861
Corporate, Non-Segment [Member]
Long-lived assets from continuing operations	749	[1]	793
Total assets from continuing operations	$ 44,058	[3]	$ 45,676

[1] Includes assets acquired in the TransGlobe acquisition

[2] Includes assets acquired in the Sasol acquisition

[3] Includes assets acquired in the TransGlobe acquisition

XML

Note 5 - Earnings Per Share - Reconciliation of Basic and Diluted EPS and Shares (Details) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2023	Jun. 30, 2022
Income (loss) from continuing operations	$ 6,754		$ 15,124		$ 10,237	$ 27,300
Income from continuing operations attributable to unvested shares	(27)		(229)		(15)	(381)
Numerator for basic	(6,727)		(14,895)		(10,222)	(26,919)
Loss from continuing operations attributable to unvested shares	0		1		(41)	2
Numerator for dilutive	6,727		14,896		10,181	26,921
Loss from discontinued operations, net of tax	(2)		(20)		(15)	(32)
Loss from discontinued operations attributable to unvested shares	0		0		0	0
Numerator for basic	(2)		(20)		(15)	(32)
(Income) loss from discontinued operations attributable to unvested shares	0		0		0	0
Numerator for dilutive	(2)		(20)		(15)	(32)
Net income (loss)	6,752	$ 3,470	15,104	$ 12,164	10,222	27,268
Net income attributable to unvested shares	(27)		(229)		(56)	(381)
Numerator for basic	6,725		14,875		10,166	26,887
Net (income) loss attributable to unvested shares	27		1		41	2
Numerator for dilutive	$ 6,752		$ 14,876		$ 10,125	$ 26,889
Basic weighted average shares outstanding (in shares)	106,965		58,925		107,175	58,814
Effect of dilutive securities (in shares)	648		436		875	464
Diluted weighted average shares outstanding (in shares)	107,613		59,361		108,050	59,278
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive (in shares)	431		251		238	154

XML

Note 6 - Revenue (Details Textual) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2023	Jun. 20, 2026	Dec. 31, 2022
Recovery Cost Assigned, Percent	100.00%
Minimum [Member]
Recovery Cost Assigned, Percent	5.00%
Cost of Oil, Percent	25.00%
Allocation of Profit, Percent	67.00%
Maximum [Member]
Recovery Cost Assigned, Percent	15.00%
Cost of Oil, Percent	40.00%
Allocation of Profit, Percent	84.00%
Egyptian General Petroleum Corporation (EGPC), Merged Concession Agreement [Member]
Ownership Percentage	50.00%
Egyptian General Petroleum Corporation (EGPC), South Ghazalat Concession Agreement [Member]
Ownership Percentage	50.00%
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Foreign Tax Authority [Member] | Tax Administration of Gabon [Member]
Income Taxes Receivable	$ 16.7		$ 2.8
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member]
Working Interest Ownership, Percentage	7.50%
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member] | Forecast [Member]
Working Interest Ownership, Percentage		10.00%
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Government of Gabon [Member]
Monthly Royalty Rate, Based on Production at the Published Price	13.00%

XML

Note 6 - Revenue - Revenues from Contracts with Customers and Other Items Not Associated with Customer Contracts (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Crude oil and natural gas sales	$ 109,240	$ 110,985	$ 189,643	$ 179,641
Selling costs	(1)		(498)
Crude oil, natural gas and natural gas liquids sales	109,240	110,985	189,643	179,641
EGYPT
Royalties	(28,892)		(48,232)
Crude oil and natural gas sales	21,308		56,092
Gross sales	50,201		104,822
Royalties	(28,892)		(48,232)
Crude oil, natural gas and natural gas liquids sales	21,308		56,092
Revenue	50,201		104,822
CANADA
Royalties	(905)		(2,098)
Crude oil and natural gas sales	10,008		18,890
Royalties	(905)		(2,098)
Crude oil, natural gas and natural gas liquids sales	10,008		18,890
Crude Oil Sales and Purchase Agreements [Member]
Sales under the COSPA or COSMA	87,478	125,143	130,079	201,629
Revenue	87,478	125,143	130,079	201,629
Crude Oil [Member] | CANADA
Gross sales	8,325		14,979
Revenue	8,325		14,979
Carried Interest Recoupment [Member]
Other items reported in revenue not associated with customer contracts	2,212	2,371	2,212	3,483
Gas [Member] | CANADA
Gross sales	703		1,661
Revenue	703		1,661
Oil and Gas [Member]
Royalties	(11,766)	(16,529)	(17,630)	(25,471)
Crude oil and natural gas sales	77,924	110,985	114,661	179,641
Royalties	(11,766)	(16,529)	(17,630)	(25,471)
Crude oil, natural gas and natural gas liquids sales	77,924	$ 110,985	114,661	$ 179,641
Natural Gas Liquids [Member] | CANADA
Sales under the COSPA or COSMA	1,885		4,348
Revenue	$ 1,885		$ 4,348

XML

Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment (Details Textual) $ in Millions				1 Months Ended		3 Months Ended	12 Months Ended
	Jun. 20, 2026	Jan. 20, 2022 USD ($)	Sep. 25, 2018	Feb. 28, 2023 USD ($)	Sep. 30, 2022 ha	Mar. 31, 2023 USD ($)	Dec. 31, 2020 USD ($)	Sep. 16, 2028	Jun. 30, 2023 USD ($)	Dec. 31, 2022 USD ($)	Oct. 13, 2022 USD ($)	Apr. 30, 2021	Apr. 12, 2021	Feb. 25, 2021 USD ($)	Mar. 31, 2020 USD ($)	Sep. 17, 2018 USD ($)	Dec. 31, 2012
Block P Offshore Equatorial Guinea [Member]
Business Acquisition, Percentage of Voting Interests Acquired																	31.00%
Additional Ownership Interest Acquired							12.00%
Asset Acquisition, Percent Interest Acquired							43.00%
Asset Acquisition, Contingent Consideration Arrangements, Range of Outcomes, Value, High							$ 3.1
Etame Marine Block [Member]
Unproved Oil and Gas Property, Successful Effort Method														$ 2.2
EQUATORIAL GUINEA
Effective Statutory Income Tax Rate, Percent					25.00%
EGYPT
Undeveloped Leasehold Value									$ 13.9		$ 13.6
CANADA
Undeveloped Leasehold Value									$ 16.7		$ 16.7
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member]
Deferred Tax Assets, Property, Plant and Equipment																$ 18.6
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Signing Bonus [Member]
Capitalized Costs, Unproved Properties																6.7
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Tax Effect [Member]
Capitalized Costs, Unproved Properties																$ 7.1
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Forecast [Member] | Etame Marine Block [Member]
Increase (Decrease) in Working Interest Ownership Percentage	1.60%
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member]
Entitled Percent for Consortium After Initial Royalty Percentage			80.00%
Period of Agreement for Exploitation Areas (Year)			10 years
Working Interest Ownership, Percentage									7.50%
Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member] | Forecast [Member]
Entitled Percent for Consortium After Initial Royalty Percentage								70.00%
Working Interest Ownership, Percentage	10.00%
Merged Concession Agreement with EGPC [Member]
Number of Concession Agreements Merged		3
Concession Agreement, Term (Year)		15 years
Annual Modernization Payments		$ 10.0
Credit issued Against Receivables		10.0
Minimum Financial Work Commitments		$ 50.0
Financial Work Commitments Duration (Year)		5 years
Etame Marine Block [Member]
Joint Venture Project, Ownership, Percent									63.575%
Unproved Oil and Gas Property, Successful Effort Method															$ 2.3
Undeveloped Leasehold Value										$ 13.7					$ 11.5
Etame Marine Block [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member]
Number of Contract Extension Periods			2
Production License Agreement Term Extended by Government (Year)			5 years
Etame Marine Block [Member] | Production Sharing Contract, September 17, 2018 Through September 16, 2028 [Member] | Forecast [Member]
Increase (Decrease) in Working Interest Ownership Percentage	2.50%
Block P Offshore Equatorial Guinea [Member]
Joint Venture Project, Ownership, Percent				60.00%									45.90%
Period of Development Area (Year)					25 years	25 years
Area of Land (Hectare) | ha					23,144
Cost Oil Maximum, Percent					70.00%
Asset Acquisition, Contingent Consideration Arrangements, Range of Outcomes, Value, High				$ 6.8
Joint Venture Project, Additional Working Interest Percentage				14.10%
Unproved Oil and Gas Property, Successful Effort Method						$ 10.0
Block P Offshore Equatorial Guinea [Member] | Crown Energy [Member]
Working Interest Ownership, Percentage												5.00%
Block P Offshore Equatorial Guinea [Member] | Royalty for the First 10,000 bopd [Member]
Percent of Oil Profit					10.00%
Block P Offshore Equatorial Guinea [Member] | Royalty for the 10,000 bopd to 25,000 bopd Tranche [Member]
Percent of Oil Profit					11.00%
Block P Offshore Equatorial Guinea [Member] | The States Share of Oil Profit Up to 25 Million bbl [Member]
Percent of Oil Profit					10.00%
Block P Offshore Equatorial Guinea [Member] | The States Share of Oil Profit Up to 25 to 50 Million bbl [Member]
Percent of Oil Profit					20.00%
Venus Development [Member]
Area of Land (Hectare) | ha					8,476

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Note 7 - Crude Oil and Natural Gas Properties and Equipment - Schedule of Crude Oil and Natural Gas Properties and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2023	Dec. 31, 2022
Gross crude oil and natural gas properties, equipment and other	$ 1,544,982	$ 1,501,935
Accumulated depreciation, depletion, amortization and impairment	(1,063,242)	(1,006,663)
Net crude oil, natural gas and NGLs properties, equipment and other	481,740	495,272
Wells and Related Equipment and Facilities [Member]
Gross crude oil and natural gas properties, equipment and other	1,446,801	1,406,888
Construction in Progress [Member]
Gross crude oil and natural gas properties, equipment and other	0	0
Undeveloped Acreage [Member]
Gross crude oil and natural gas properties, equipment and other	54,346	56,251
Other Capitalized Property Plant and Equipment [Member]
Gross crude oil and natural gas properties, equipment and other	$ 43,835	$ 38,796

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Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment - Contract Terms (Details)	6 Months Ended
	Jun. 30, 2023 MMBbls
Merged Concession [Member]
Year acquired (1)	2020	[1]
Development (Year)	5 years
Maximum cost oil	40.00%
Excess cost oil - Contractor	15.00%
Operating	100.00%
Capital	6.00%
Contractor	30.00%
Government	70.00%
Merged Concession [Member] | Minimum [Member]
Production Tranche (MBopd) (Million Barrels of Oil)	0
Merged Concession [Member] | Maximum [Member]
Production Tranche (MBopd) (Million Barrels of Oil)	25
Egyptian General Petroleum Corporation (EGPC), South Ghazalat Concession Agreement [Member]
Year acquired (1)	2013	[1]
Development (Year)	25 years
Maximum cost oil	25.00%
Excess cost oil - Contractor	5.00%
Operating	100.00%
Capital	5.00%
Contractor	17.00%
Government	83.00%
Egyptian General Petroleum Corporation (EGPC), South Ghazalat Concession Agreement [Member] | Minimum [Member]
Production Tranche (MBopd) (Million Barrels of Oil)	0
Egyptian General Petroleum Corporation (EGPC), South Ghazalat Concession Agreement [Member] | Maximum [Member]
Production Tranche (MBopd) (Million Barrels of Oil)	5

[1] Represents the year acquired by TransGlobe, prior to the Arrangement.

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Note 7 - Crude Oil, Natural Gas and NGLs Properties and Equipment - Crude Oil Production (Details)	Jun. 30, 2023
Government [Member] | Less Than or Equal to $40 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	67.00%
Government [Member] | Less Than or Equal to $40 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	68.00%
Government [Member] | Less Than or Equal to $40 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	69.00%
Government [Member] | Less Than or Equal to $40 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	70.00%
Government [Member] | Less Than or Equal to $40 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	71.00%
Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	68.00%
Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	69.00%
Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	70.00%
Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	71.00%
Government [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	72.00%
Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	70.00%
Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	71.00%
Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	72.00%
Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	74.00%
Government [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	76.00%
Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	72.50%
Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	73.00%
Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	74.00%
Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	76.00%
Government [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	78.00%
Government [Member] | More Than $100 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	75.00%
Government [Member] | More Than $100 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	76.00%
Government [Member] | More Than $100 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	77.00%
Government [Member] | More Than $100 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	78.00%
Government [Member] | More Than $100 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	80.00%
Contractor [Member] | Less Than or Equal to $40 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	33.00%
Contractor [Member] | Less Than or Equal to $40 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	32.00%
Contractor [Member] | Less Than or Equal to $40 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	31.00%
Contractor [Member] | Less Than or Equal to $40 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	30.00%
Contractor [Member] | Less Than or Equal to $40 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	29.00%
Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	32.00%
Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	31.00%
Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	30.00%
Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	29.00%
Contractor [Member] | More Than $40/bbl and Less Than or Equal to $60 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	28.00%
Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	30.00%
Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	29.00%
Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	28.00%
Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	26.00%
Contractor [Member] | More Than $60/bbl and Less Than or Equal to $80 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	24.00%
Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	27.50%
Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	27.00%
Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	26.00%
Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	24.00%
Contractor [Member] | More Than $80/bbl and Less Than or Equal to $100 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	22.00%
Contractor [Member] | More Than $100 bbl [Member] | Less Than or Equal to 5 MBopd [Member]
Percent of oil production assigned	25.00%
Contractor [Member] | More Than $100 bbl [Member] | More Than 5 MBopd and Less Than or Equal to 10 MBopd [Member]
Percent of oil production assigned	24.00%
Contractor [Member] | More Than $100 bbl [Member] | More Than 10 MBopd and Less Than or Equal to 15 MBopd [Member]
Percent of oil production assigned	23.00%
Contractor [Member] | More Than $100 bbl [Member] | More Than 15 MBopd and Less Than or Equal to 25 MBopd [Member]
Percent of oil production assigned	22.00%
Contractor [Member] | More Than $100 bbl [Member] | More Than 25 MBopd [Member]
Percent of oil production assigned	20.00%

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Note 8 - Derivatives and Fair Value - Unexpired Barrels (Details) - Commodity Contract One, April 2023 Through June 2023 [Member]	Jun. 30, 2023 $ / item $ / bbl bbl
Barrels (Barrel of Oil) | bbl	95,000
Weighted average price put price (in USD per Barrel of Oil) | $ / bbl	65.00
Weighted average price call price (in USD per Per Share) | $ / item	96.00

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Note 8 - Derivatives and Fair Value - Gain Loss on Derivative Instruments (Details) - Crude Oil Swaps [Member] - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Derivative instruments loss, net	$ 31	$ (9,542)	$ 52	$ (41,300)
Cash Settlements Paid on Matured Derivative Contracts, Net [Member]
Derivative instruments loss, net	(4)	(21,059)	(63)	(33,559)
Unrealized Gain (Loss) [Member]
Derivative instruments loss, net	$ 35	$ 11,517	$ 115	$ (7,741)

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Note 9 - Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other Balances (Details) - USD ($) $ in Thousands	Jun. 30, 2023	Dec. 31, 2022
Accrued accounts payable invoices	$ 21,480	$ 28,360
Gabon DMO, PID and PIH obligations	12,782	10,509
Capital expenditures	19,770	26,618
Stock appreciation rights – current portion	32	570
Accrued wages and other compensation	2,726	8,161
ARO Obligation	5,729	306
Egypt modernization payments	9,373	9,933
Excess cost oil payable	8,099	0
Other	4,113	6,935
Total accrued liabilities and other	$ 84,104	$ 91,392

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Note 10 - Commitments and Contingencies (Details Textual)							3 Months Ended		6 Months Ended		12 Months Ended			36 Months Ended
	Aug. 09, 2023 $ / shares	May 09, 2023 $ / shares	Nov. 01, 2022 USD ($)	Aug. 20, 2022 USD ($)	Feb. 01, 2022 USD ($)	Jan. 20, 2022 USD ($)	Jun. 30, 2023 USD ($)	Mar. 31, 2023 USD ($)	Jun. 30, 2023 USD ($)	Jun. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2016	Dec. 31, 2021	Feb. 01, 2026 USD ($)	Feb. 01, 2025 USD ($)	Oct. 13, 2022 USD ($)	Jan. 19, 2022 USD ($)	Nov. 30, 2021 USD ($)	Sep. 30, 2020
Estimated Abandonment Costs																			$ 47,800,000
Abandonment Funding							$ 6,268,000		$ 6,268,000	$ 20,091,000	$ 20,586,000
Payments for Abandonment Funding								$ 15,600,000				$ 0
Dividends Payable, Amount Per Share (in dollars per share) | $ / shares		$ 0.0625
Increase (Decrease) in Other Receivables									1,868,000	$ 943,000
Dividends Payable, Date Declared		May 09, 2023
Dividends Payable, Date to be Paid		Jun. 23, 2023
Parent Company [Member]
Contractual Obligation, Total							26,800,000		26,800,000
Parent Company [Member] | Accrued Liabilities and Other [Member]
Contractual Obligation, Total							9,400,000		9,400,000
Parent Company [Member] | Other Long-term Liabilities [Member]
Contractual Obligation, Total							17,500,000		17,500,000
TransGlobe [Member]
Other Receivables							50,300,000		50,300,000								$ 67,500,000	$ 67,500,000
Egyptian General Petroleum Corporation (EGPC) [Member]
Contractual Obligation, Total							150,000,000		$ 150,000,000
Increase (Decrease) in Other Receivables											$ (10,000,000.0)
Development Timeframe (Year)									5 years
Egyptian General Petroleum Corporation (EGPC) [Member] | Minimum [Member]
Contractual Obligation, Total							50,000,000.0		$ 50,000,000.0
Sogara [Member]
Other Receivables							19,700,000		19,700,000
Share Buyback Program [Member]
Stock Repurchase Program, Authorized Amount			$ 30,000,000
Stock Repurchase Program, Period in Force (Month)			20 months
Subsequent Event [Member]
Dividends Payable, Amount Per Share (in dollars per share) | $ / shares	$ 0.0625
Dividends Payable, Date Declared	Aug. 09, 2023
Dividends Payable, Date to be Paid	Sep. 22, 2023
Foreign Tax Authority [Member] | Tax Administration of Gabon [Member]
Income Tax Examination, Year under Examination													2013 2014	2015 2016
FPSO Charter [Member]
Estimated Abandonment Costs							5,600,000		5,600,000
Number of Charter Extension Periods																				2
Charter Day Rates				$ 150,000
Other Demobilization Fees, Gross				15,300,000
Other Demobilization Fees, Net				$ 8,900,000			5,600,000
FPSO Charter [Member] | Vaalco Energy Inc. and Other Etame Marin Block Owners [Member]
Estimated Abandonment Costs							$ 9,600,000		$ 9,600,000
Etame Marine Block [Member]
Abandonment Funding								6,300,000
Payments for Abandonment Funding								15,600,000
Etame Marine Block [Member]
Estimated Abandonment Costs																			$ 81,300,000
Abandonment Funding								10,700,000
Payments for Abandonment Funding								$ 26,600,000
Egyptian General Petroleum Corporation (EGPC) [Member] | Merged Concession Agreement [Member]
Payments for Merger Related Costs, First Modernization Payment						$ 15,000,000.0
Payments for Merger Related Costs, Signature Bonus						$ 1,000,000.0
Payments for Merger Related Costs, Second Modernization Payment					$ 10,000,000.0
Egyptian General Petroleum Corporation (EGPC) [Member] | Merged Concession Agreement [Member] | Forecast [Member]
Contractual Obligation, Total															$ 10,000,000.0	$ 10,000,000.0

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Note 10 - Commitments and Contingencies - Schedule of Equity Securities Repurchased (Details) - USD ($)		1 Months Ended					3 Months Ended
	Aug. 08, 2023	Aug. 08, 2023	Jul. 31, 2023	Jun. 30, 2023	May 31, 2023	Apr. 30, 2023	Jun. 30, 2023
Number of Shares Purchased (in shares)							1,160,976
Number of Shares Purchased (in shares)							1,160,976
Shares Purchased as Part of Publicly Announced Programs [Member]
Number of Shares Purchased (in shares)							1,160,976
Number of Shares Purchased (in shares)							1,160,976
Shares Purchased as Part of Publicly Announced Programs [Member] | Subsequent Event [Member]
Number of Shares Purchased (in shares)		604,131
Number of Shares Purchased (in shares)		604,131
Share Repurchase Program [Member] | Subsequent Event [Member]
Number of Shares Purchased (in shares)		604,131
Number of Shares Purchased (in shares)		604,131
Common Stock [Member]
Number of Shares Purchased (in shares)				494,164	362,843	303,969
Average Price Paid per Share (in dollars per share)				$ 4.05	$ 4.14	$ 4.94
Stock Repurchase Program, Authorized Amount				$ 17,504,007	$ 19,502,740	$ 21,003,245	$ 17,504,007
Number of Shares Purchased (in shares)				494,164	362,843	303,969
Average Price Paid per Share (in dollars per share)				$ 4.05	$ 4.14	$ 4.94
Authorized Amount				$ 17,504,007	$ 19,502,740	$ 21,003,245	17,504,007
Common Stock [Member] | Shares Purchased as Part of Publicly Announced Programs [Member]
Number of Shares Purchased (in shares)				494,164	362,843	303,969
Average Price Paid per Share (in dollars per share)				$ 4.05	$ 4.14	$ 4.94
Stock Repurchase Program, Authorized Amount				$ 17,504,007	$ 19,502,740	$ 21,003,245	17,504,007
Number of Shares Purchased (in shares)				494,164	362,843	303,969
Average Price Paid per Share (in dollars per share)				$ 4.05	$ 4.14	$ 4.94
Authorized Amount				$ 17,504,007	$ 19,502,740	$ 21,003,245	$ 17,504,007
Common Stock [Member] | Shares Purchased as Part of Publicly Announced Programs [Member] | Subsequent Event [Member]
Number of Shares Purchased (in shares)	98,411		505,720
Average Price Paid per Share (in dollars per share)	$ 4.29		$ 3.96
Stock Repurchase Program, Authorized Amount	$ 15,082,133	$ 15,082,133	$ 15,504,180
Number of Shares Purchased (in shares)	98,411		505,720
Average Price Paid per Share (in dollars per share)	$ 4.29		$ 3.96
Authorized Amount	$ 15,082,133	$ 15,082,133	$ 15,504,180

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Note 11 - Debt (Details Textual) $ in Thousands, $ in Millions			1 Months Ended
	May 16, 2025	May 16, 2022 USD ($)	Oct. 31, 2022 CAD ($)	Jun. 30, 2023 USD ($)	Dec. 31, 2022 USD ($)
Long-Term Debt, Total				$ 0	$ 0
Revolving Credit Facility [Member]
Line of Credit Facility, Maximum Borrowing Capacity		$ 50,000
The Facility [Member] | Revolving Credit Facility [Member]
Line of Credit Facility, Maximum Borrowing Capacity		50,000
Line of Credit Facility, Maximum Optional Increase in Maximum Borrowing Capacity		50,000
Line of Credit Facility, Additional Commitment in Maximum Borrowing Capacity, Yearly Decrease		$ 6,250
Line of Credit Facility, Commitment Fee Percentage, Commitments or Borrowing Base Exceeds Outstanding Utilizations		35.00%
Line of Credit Facility, Commitment Fee Percentage, Total Commitments Exceeds Borrowing Base		20.00%
Debt Instrument, Covenant, Maximum Total Net Debt to EBITDA		3.0
Debt Instrument, Covenant, Minimum Cash and Cash Equivalents		$ 10,000
Line of Credit Facility, Current Borrowing Capacity				50,000
Long-Term Line of Credit				0
Debt Issuance Costs, Net		1,700
Debt Issuance Costs, Gross		2,100
Amortization of Debt Issuance Costs		$ 400
The Facility [Member] | Revolving Credit Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate [Member]
Debt Instrument, Basis Spread on Variable Rate		6.00%
The Facility [Member] | Revolving Credit Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate [Member] | Forecast [Member]
Debt Instrument, Basis Spread on Variable Rate	6.25%
ATB Financial [Member] | TransGlobe [Member]
Repayments of Long-Term Lines of Credit			$ 4.1
Glencore [Member] | Revolving Credit Facility [Member]
Line of Credit Facility, Maximum Borrowing Capacity				$ 50,000

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Note 12 - Leases (Details Textual) $ in Millions	Jun. 30, 2023 USD ($)
Oil and Gas Joint Interest Billing Receivables	$ 49.8
Lessee, Operating And Finance Lease Liability, Payments Due	$ 122.8
Minimum [Member]
Lessee, Operating Lease, Term of Contract (Month)	5 months
Lessee, Finance Lease, Term of Contract (Year)	35 years
Maximum [Member]
Lessee, Operating Lease, Term of Contract (Month)	21 months
Lessee, Finance Lease, Term of Contract (Year)	4 years

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Note 12 - Leases - Components of Lease Costs and Supplemental Information (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Finance lease cost (1)	[1]	$ 4,115	$ 98	$ 8,480	$ 164
Operating lease cost		339	4,265	922	8,461
Short-term lease cost (2)	[2]	1,660	199	3,020	1,213
Variable lease cost (3)	[3]	0	1,909	0	3,247
Total lease expense		6,114	6,471	12,422	13,085
Lease costs capitalized		7	651	55	1,423
Total lease costs		$ 6,121	$ 7,122	12,477	14,508
Financing cash flows attributable to finance leases (in thousands)				$ 3,379	$ 26
Weighted-average remaining lease term (in years) (Year)		8 years 11 months 15 days	5 years 2 months 1 day	8 years 11 months 15 days	5 years 2 months 1 day
Weighted-average discount rate		8.11%	3.54%	8.11%	3.54%
Operating cash flows attributable to operating leases (in thousands)				$ 423	$ 12,816
Weighted-average remaining lease term (in years) (Year)		11 months 12 days	8 months 12 days	11 months 12 days	8 months 12 days
Weighted-average discount rate		10.33%	5.62%	10.33%	5.62%

[1] Represents depreciation and interest associated with financing leases.

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

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

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Note 12 - Leases - Lease Cost on the Consolidated Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Total lease expense	$ 6,117	$ 6,708	$ 12,442	$ 13,603
Lease costs capitalized	4	414	35	905
Total lease costs	6,121	7,122	12,477	14,508
Finance Lease Cost [Member]
Total lease expense	2,376	57	5,001	96
Production Expense [Member]
Total lease expense	1,208	3,720	2,494	7,558
General and Administrative Expense [Member]
Total lease expense	52	47	98	63
Lease Costs Billed to Joint Venture Owners [Member]
Total lease expense	$ 2,481	$ 2,884	$ 4,849	$ 5,886

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Note 12 - Leases - Future Maturities of Lease Liabilities (Details) $ in Thousands	Jun. 30, 2023 USD ($)
2023, operating leases	$ 1,173
2023, finance leases	7,287
2024, operating leases	672
2024, finance leases	14,448
2025, operating leases	32
2025, finance leases	16,202
2026, operating leases	0
2026, finance leases	16,478
2027, operating leases	0
2027, finance leases	15,023
Thereafter, operating leases	0
Thereafter, finance leases	51,527
Total due, operating leases	1,877
Total due, finance leases	120,965
Less: imputed interest, operating leases	80
Less: imputed interest, finance leases	33,425
Total lease liabilities, operating leases	1,797
Total lease liabilities, finance leases	$ 87,540

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Note 13 - Asset Retirement Obligations (Details Textual) - USD ($) $ in Thousands	1 Months Ended	6 Months Ended	12 Months Ended
	Oct. 31, 2022	Jun. 30, 2023	Dec. 31, 2022
Asset Retirement Obligation, Liabilities Incurred	$ 6,100	$ 0	$ 6,134
Asset Retirement Obligation, Liabilities Settled	6,600	374	6,577
Costs Associated With Retirement Obligation, Included In Accrued Liabilities		$ 5,600
EGYPT
Decommissioning Liability, Noncurrent	$ 0		$ 0

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Note 13 - Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	1 Months Ended	6 Months Ended	12 Months Ended
	Oct. 31, 2022	Jun. 30, 2023	Dec. 31, 2022
Beginning balance		$ 42,001	$ 40,694
Accretion		1,118	1,958
Additions	$ 6,100	0	6,134
Revisions		5,726	(43)
Settlements	$ (6,600)	(374)	(6,577)
Foreign currency gain (loss)		216	(165)
Ending balance		$ 48,687	$ 42,001

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Note 14 - Shareholders' Equity (Details Textual) - USD ($) $ / shares in Units, $ in Millions	Nov. 01, 2022	Oct. 13, 2022	Jun. 30, 2023	Dec. 31, 2022	Oct. 12, 2022
Common Stock, Shares Authorized (in shares)		160,000,000	160,000,000	160,000,000	100,000,000
Preferred Stock, Shares Authorized (in shares)			500,000	500,000
Preferred Stock, Par or Stated Value Per Share (in dollars per share)			$ 25	$ 25
Preferred Stock, Shares Issued (in shares)			0	0
Stock Repurchase Program 2019 [Member]
Stock Repurchase Program, Authorized Amount	$ 30
Stock Repurchase Program, Period in Force (Month)	20 months
TransGlobe [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares (in shares)		49,300,000

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Note 14 - Shareholders' Equity - Schedule of Equity Securities Repurchased (Details) - USD ($)	1 Months Ended			3 Months Ended
	Jun. 30, 2023	May 31, 2023	Apr. 30, 2023	Jun. 30, 2023
Number of Shares Purchased (in shares)				1,160,976
Number of Shares Purchased (in shares)				1,160,976
Shares Purchased as Part of Publicly Announced Programs [Member]
Number of Shares Purchased (in shares)				1,160,976
Number of Shares Purchased (in shares)				1,160,976
Common Stock [Member]
Number of Shares Purchased (in shares)	494,164	362,843	303,969
Average Price Paid per Share (in dollars per share)	$ 4.05	$ 4.14	$ 4.94
Number of Shares Purchased (in shares)	494,164	362,843	303,969
Authorized Amount	$ 17,504,007	$ 19,502,740	$ 21,003,245	$ 17,504,007
Common Stock [Member] | Shares Purchased as Part of Publicly Announced Programs [Member]
Number of Shares Purchased (in shares)	494,164	362,843	303,969
Average Price Paid per Share (in dollars per share)	$ 4.05	$ 4.14	$ 4.94
Number of Shares Purchased (in shares)	494,164	362,843	303,969
Authorized Amount	$ 17,504,007	$ 19,502,740	$ 21,003,245	$ 17,504,007

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Note 15 - Stock-based Compensation and Other Benefit Plans (Details Textual) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2023	Jun. 30, 2021	Jun. 30, 2023	Dec. 31, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jun. 25, 2020
Proceeds from Stock Options Exercised					$ 0.4	$ 0.3
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Grants in Period, Gross (in shares)	334,753
Share-Based Compensation Arrangements by Share-Based Payment Award, Options, Grants in Period, Weighted Average Exercise Price (in dollars per share)	$ 4.19
Severance Cost as Percentage of Target Bonus	75.00%		75.00%		75.00%
Maximum [Member]
Severance Cost as Percentage of Salary					100.00%
Minimum [Member]
Severance Cost as Percentage of Salary					50.00%
Stock Appreciation Rights (SARs) [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Share-Based Liabilities Paid					$ 0.2	$ 0.8
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period (in shares)					0
Share-Based Payment Arrangement, Option [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year)					3 years
Share-Based Payment Arrangement, Shares Withheld for Tax Withholding Obligation (in shares)					44,655
Share-Based Payment Arrangement, Option [Member] | Share-Based Payment Arrangement, Tranche One [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year)	1 year
Share-Based Compensation Arrangement by Share-Based Payment Award, Expiration Period (Year)	10 years
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	33.33%
Share-based Compensation Arrangement By Share-based Payment Award, Award Vesting Rights, Minimum Share Price Over 30 Day Period (in dollars per share)	$ 4.82
Share-Based Payment Arrangement, Option [Member] | Share-Based Payment Arrangement, Tranche Two [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year)	2 years
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	33.33%
Share-based Compensation Arrangement By Share-based Payment Award, Award Vesting Rights, Minimum Share Price Over 30 Day Period (in dollars per share)	$ 5.54
Share-Based Payment Arrangement, Option [Member] | Share-Based Payment Arrangement, Tranche Three [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year)	3 years
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	33.33%
Share-based Compensation Arrangement By Share-based Payment Award, Award Vesting Rights, Minimum Share Price Over 30 Day Period (in dollars per share)	$ 6.37
Restricted Stock [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year)								3 years
Share-Based Payment Arrangement, Shares Withheld for Tax Withholding Obligation (in shares)					81,342
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)					12,000
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period (in shares)					797,000
Performance Share Units (PSUs) [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year)				3 years
Share-Based Payment Arrangement, Shares Withheld for Tax Withholding Obligation (in shares)					147,862
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Target Percentage							64.40%
Performance Share Units (PSUs) [Member] | Awards Granted, 2021 and 2020 [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Target Percentage								200.00%	200.00%
Restricted Stock Units (RSUs) [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period (Year)							3 years
Share-Based Payment Arrangement, Shares Withheld for Tax Withholding Obligation (in shares)					162,328
Deferred Share Units [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Vested, Outstanding (in shares)	101,313		101,313		101,313
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Converted in Period (in shares)			358,563
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)			65,582
The 2020 Long-Term Incentive Plan [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Number of Shares Authorized (in shares)										5,500,000
Share-Based Compensation Arrangement by Share-Based Payment Award, Number of Additional Shares Authorized (in shares)		3,750,000
Share-Based Compensation Arrangement by Share-Based Payment Award, Number of Shares Available for Grant (in shares)	1,718,603		1,718,603		1,718,603

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Note 15 - Stock-based Compensation and Other Benefit Plans - Stock-based Compensation (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Total stock-based compensation	$ 605	$ 842	$ 1,254	$ 2,264
Equity Awards [Member]
Total stock-based compensation	706	615	1,381	1,019
Liability Awards [Member]
Total stock-based compensation	$ (101)	$ 227	$ (127)	$ 1,245

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Note 15 - Stock-based Compensation and Other Benefit Plans - Weighted Average Assumptions (Details) - $ / shares	5 Months Ended	17 Months Ended
	Jun. 30, 2022	Jun. 30, 2023
Weighted average exercise price - ($/share) (in dollars per share)	$ 6.41	$ 4.19
Expected life in years (Year)	6 years	6 years 4 months 24 days
Average expected volatility	72.00%	68.00%
Risk-free interest rate	1.98%	3.73%
Expected dividend yield	2.30%	5.97%
Weighted average grant date fair value - ($/share) (in dollars per share)	$ 2.84	$ 2.29

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Note 15 - Stock-based Compensation and Other Benefit Plans - Stock Option Activity (Details) $ / shares in Units, $ in Thousands	1 Months Ended	6 Months Ended
	Jun. 30, 2023 USD ($) $ / shares shares	Jun. 30, 2023 USD ($) $ / shares shares
Granted, number of shares (in shares) | shares	334,753
Granted, weighted average exercise price (in dollars per share)	$ 4.19
Monte Carle Model [Member]
Outstanding, number of shares (in shares) | shares		444
Outstanding, weighted average exercise price (in dollars per share)		$ 3.95
Granted, number of shares (in shares) | shares		335
Granted, weighted average exercise price (in dollars per share)		$ 4.19
Exercised, number of shares (in shares) | shares		(74)
Exercised, weighted average exercise price (in dollars per share)		$ (1.68)
Unvested shares forfeited, number of shares (in shares) | shares		0
Unvested shares forfeited, weighted average exercise price (in dollars per share)		$ 0
Vested shares expired, number of shares (in shares) | shares		0
Vested shares expired, weighted average exercise price (in dollars per share)		$ 0
Outstanding, number of shares (in shares) | shares	705	705
Outstanding, weighted average exercise price (in dollars per share)	$ 4.30	$ 4.30
Outstanding, weighted average remaining contractual term (Year)		8 years 11 months 12 days
Outstanding, aggregate intrinsic value | $	$ 280	$ 280
Exercisable, number of shares (in shares) | shares	211	211
Exercisable, weighted average exercise price (in dollars per share)	$ 3.34	$ 3.34
Exercisable, weighted average remaining contractual term (Year)		7 years 8 months 12 days
Exercisable, aggregate intrinsic value | $	$ 262	$ 262
Unvested shares forfeited, weighted average exercise price (in dollars per share)		$ (0)
Black-scholes Model [Member]
Outstanding, number of shares (in shares) | shares		387
Outstanding, weighted average exercise price (in dollars per share)		$ 1.86
Granted, number of shares (in shares) | shares		0
Granted, weighted average exercise price (in dollars per share)		$ 0
Exercised, number of shares (in shares) | shares		(164)
Exercised, weighted average exercise price (in dollars per share)		$ (1.56)
Unvested shares forfeited, number of shares (in shares) | shares		0
Unvested shares forfeited, weighted average exercise price (in dollars per share)		$ 0
Vested shares expired, number of shares (in shares) | shares		0
Vested shares expired, weighted average exercise price (in dollars per share)		$ 0
Outstanding, number of shares (in shares) | shares	223	223
Outstanding, weighted average exercise price (in dollars per share)	$ 2.07	$ 2.07
Outstanding, weighted average remaining contractual term (Year)		8 months 23 days
Outstanding, aggregate intrinsic value | $	$ 376	$ 376
Exercisable, number of shares (in shares) | shares	223	223
Exercisable, weighted average exercise price (in dollars per share)	$ 2.07	$ 2.07
Exercisable, weighted average remaining contractual term (Year)		8 months 23 days
Exercisable, aggregate intrinsic value | $	$ 376	$ 376
Unvested shares forfeited, weighted average exercise price (in dollars per share)		$ 0

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Note 15 - Stock-based Compensation and Other Benefit Plans - Summary of Activity for Restricted Shares (Details) - Restricted Stock [Member] shares in Thousands	6 Months Ended
	Jun. 30, 2023 $ / shares shares
Non-vested shares outstanding (in shares) | shares	665
Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.59
Awards granted (in shares) | shares	797
Awards granted, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.19
Awards vested (in shares) | shares	(354)
Awards vested, weighted average grant date fair value (in dollars per share) | $ / shares	$ 3.92
Awards forfeited (in shares) | shares	(12)
Awards forfeited, weighted average grant date fair value (in dollars per share) | $ / shares	$ 5.73
Non-vested shares outstanding (in shares) | shares	1,096
Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.51
The 2020 Plan [Member]
Non-vested shares outstanding (in shares) | shares	383
Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.27
Awards vested (in shares) | shares	(259)
Awards vested, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.27
Awards forfeited (in shares) | shares	(23)
Awards forfeited, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.27
Non-vested shares outstanding (in shares) | shares	284
Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.22

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Note 15 - Stock-based Compensation and Other Benefit Plans - Summary of Activity for Performance Shares (Details) - Performance Shares [Member] - The 2020 Plan [Member] shares in Thousands	6 Months Ended
	Jun. 30, 2023 $ / shares shares
Non-vested shares outstanding (in shares) | shares	690
Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.27
Awards vested (in shares) | shares	(514)
Awards vested, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.27
Awards forfeited (in shares) | shares	(36)
Awards forfeited, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.27
Non-vested shares outstanding (in shares) | shares	140
Non-vested shares outstanding, weighted average grant date fair value (in dollars per share) | $ / shares	$ 4.27

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Note 15 - Stock-based Compensation and Other Benefit Plans - SAR Activity (Details) - Stock Appreciation Rights (SARs) [Member] $ / shares in Units, shares in Thousands, $ in Thousands	6 Months Ended
	Jun. 30, 2023 USD ($) $ / shares shares
Outstanding, number of underlying shares (in shares) | shares	202
Outstanding, weighted average exercise price per share (in dollars per share) | $ / shares	$ 1.87
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Grants in Period (in shares) | shares	0
Granted, weighted average exercise price per share (in dollars per share) | $ / shares	$ 0
Exercised, number of underlying shares (in shares) | shares	(63)
Exercised, weighted average exercise price per share (in dollars per share) | $ / shares	$ 0.86
Unvested SARs forfeited, number of underlying shares (in shares) | shares	0
Unvested SARs forfeited, weighted average exercise price per share (in dollars per share) | $ / shares	$ 0
Vested SARs expired, number of underlying shares (in shares) | shares	0
Vested SARs expired, weighted average exercise price per share (in dollars per share) | $ / shares	$ 0
Outstanding, number of underlying shares (in shares) | shares	139
Outstanding, weighted average exercise price per share (in dollars per share) | $ / shares	$ 2.33
Outstanding, weighted average remaining contractual term (Year)	7 months 20 days
Outstanding, aggregate intrinsic value | $	$ 198
Exercisable, number of underlying shares (in shares) | shares	139
Exercisable, weighted average exercise price per share (in dollars per share) | $ / shares	$ 2.33
Exercisable, weighted average remaining contractual term (Year)	7 months 20 days
Exercisable, aggregate intrinsic value | $	$ 198

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Note 16 - Income Taxes (Details Textual) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Effective Income Tax Rate Reconciliation, Percent	68.42%	73.37%	63.32%	72.59%
Income Tax Expense (Benefit), Favorable (Unfavorable) Oil Price Adjustment	$ 500	$ 1,200	$ 2,700	$ 4,300
Current Income Tax Expense (Benefit)		20,400	24,700	26,100
Current Foreign Income Tax Expense (Benefit), Net Of Oil Price Adjustment		$ 19,200	22,000	21,800
Valuation Allowance, Deferred Tax Asset, Change in Amount, Discrete Item				$ 12,700
Unrecognized Tax Benefits	$ 0		$ 0

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Note 16 - Income Taxes - Provision for Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Current	$ 0	$ 0	$ 0	$ 0
Deferred	871	2,617	1,457	(9,869)
Current	12,401	20,402	24,701	26,093
Deferred	(1,684)	23,233	201	25,400
Total	$ 11,588	$ 46,252	$ 26,359	$ 41,624

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Note 17 - Other Comprehensive Income (Details Textual) $ in Millions	3 Months Ended
	Jun. 30, 2023 USD ($)
Other Comprehensive Income (Loss), Net of Tax	$ 2

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Note 17 - Other Comprehensive Income - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Jun. 30, 2023	Mar. 31, 2023
Balance	$ 455,175	$ 466,105
Balance	452,006	455,175
Accumulated Foreign Currency Adjustment Attributable to Parent [Member]
Balance	1,054	1,179
Accumulated other comprehensive income (loss) before reclassifications	2,006	(125)
Balance	$ 3,060	$ 1,054