egy-20260630

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________

FORM 10-Q

______________________

(Mark One)


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

For the quarterly period ended June 30, 2026


o			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.)

2500 CityWest Blvd. Suite 400 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 x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

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. o

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

As of August 4, 2026, there were outstanding 105,191,778 shares of common stock, $0.10 par value per share, of the registrant.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets June 30 , 2026 and December 31, 2025			2
Condensed Consolidated Statements of Operations and Comprehensive Income Three and Six Months Ended June 30 , 2026 and 2025			3
Condensed Consolidated Statements of Shareholders’ Equity Three and Six Months Ended June 30 , 2026 and 2025			4
Condensed Consolidated Statements of Cash Flows Six Months Ended June 30 , 2026 and 2025			5
Notes to Condensed Consolidated Financial Statements (unaudited)			7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			22
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			34
ITEM 4. CONTROLS AND PROCEDURES			36
PART II. OTHER INFORMATION			37
ITEM 1. LEGAL PROCEEDINGS			37
ITEM 1A. RISK FACTORS			37
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			37
ITEM 5. OTHER INFORMATION			37
ITEM 6. EXHIBITS			38

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PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)


(in thousands, except share amounts)	As of June 30, 2026		As of December 31, 2025

ASSETS
Current assets:
Cash and cash equivalents	$	30,394	$	58,900
Restricted cash	112		136
Receivables:
Trade	21,465		39,924
Accounts with joint venture owners, net of allowance for credit losses of $3.1 million and $2.7 million, respectively	7,302		5,420
Other, net of allowance for credit losses of $0.4 million and $— million, respectively	1,603		2,277
Crude oil inventory	5,106		1,774
Prepayments and other	22,910		24,370
Current assets held for sale	—		179
Total current assets	88,892		132,980
Crude oil, natural gas and NGLs properties and equipment, net	709,653		586,095
Other noncurrent assets:
Restricted cash	1,659		1,659
Value added tax and other receivables	8,056		7,149
Right of use operating lease assets	21,779		16,596
Right of use finance lease assets	62,704		68,615
Deferred tax assets	60,966		54,825
Abandonment funding	6,268		6,268
Other long-term assets	8,593		7,362
Noncurrent assets held for sale	—		31,826
Total assets	$	968,570	$	913,375
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	41,006	$	44,661
Accounts with joint venture owners	106		3,193
Accrued liabilities and other	135,824		106,444

Operating lease liabilities - current portion	6,987		5,744
Finance lease liabilities - current portion	12,337		12,119
Foreign income taxes payable	7,650		19,656
Current liabilities held for sale	—		183
Total current liabilities	203,910		192,000
Asset retirement obligations	81,635		78,406
Operating lease liabilities - net of current portion	14,631		11,183
Finance lease liabilities - net of current portion	50,825		57,256
Deferred tax liabilities	60,234		63,630
Long-term debt	177,000		60,000

Noncurrent liabilities held for sale	—		7,403
Total liabilities	588,235		469,878
Commitments and Contingencies (Note 9)
Shareholders’ equity:
Preferred stock, $25 par value; 500,000 shares authorized, none issued	—		—
Common stock, $0.10 par value; 160,000,000 shares authorized, 124,320,737 and 123,017,656 shares issued, and 105,191,778 and 104,258,253 shares outstanding, respectively	12,432		12,302
Additional paid-in capital	371,427		368,536
Accumulated other comprehensive loss	—		(498)
Less treasury stock, 19,128,959 and 18,759,403 shares, respectively, at cost	(80,718)		(78,733)
Retained earnings	77,194		141,890
Total shareholders’ equity	380,335		443,497
Total liabilities and shareholders’ equity	$	968,570	$	913,375

See notes to unaudited condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
	(in thousands, except per share amounts)
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	135,166	$	96,893	$	197,765	$	207,222
Operating costs and expenses:
Production expense	45,470		40,393		73,849		85,198

Exploration expense	65		2,520		22,459		2,520
Depreciation, depletion and amortization	34,272		28,273		52,484		58,578
Loss on sale of assets	—		—		1,202		—
General and administrative expense	11,194		8,496		19,470		17,548
Credit losses and other	573		29		844		2
Total operating costs and expenses	91,574		79,711		170,308		163,846

Operating income	43,592		17,182		27,457		43,376
Other income (expense):
Derivative gain (loss), net	18,720		400		(51,861)		326
Interest expense, net	(2,750)		(2,572)		(4,449)		(3,866)

Other income (expense), net	(325)		353		(1,359)		(659)
Total other income (expense), net	15,645		(1,819)		(57,669)		(4,199)
Income (loss) before income taxes	59,237		15,363		(30,212)		39,177
Income tax expense	16,792		6,983		21,107		23,066
Net income (loss)	$	42,445	$	8,380	$	(51,319)	$	16,111
Other comprehensive income
Currency translation adjustments	—		4,759		112		4,876
Comprehensive income (loss)	$	42,445	$	13,139	$	(51,207)	$	20,987

Basic net income (loss) per share:
Net income (loss) per share	$	0.39	$	0.08	$	(0.49)	$	0.15
Basic weighted average shares outstanding	104,518		103,936		104,389		103,848
Diluted net income (loss) per share:
Net income (loss) per share	$	0.39	$	0.08	$	(0.49)	$	0.15
Diluted weighted average shares outstanding	104,643		103,958		104,389		103,872

See notes to unaudited condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)


	Common Shares Issued	Treasury Shares	Common Stock		Additional Paid-In Capital		Accumulated Other Comprehensive Income (Loss)		Treasury Stock		Retained Earnings		Total
	(in thousands)
Balance at January 1, 2026	123,018	(18,759)	$	12,302	$	368,536	$	(498)	$	(78,733)	$	141,890	$	443,497

Stock-based compensation expense	—	—	—		1,360		—		—		—		1,360

Dividend distributions ($0.0625 per share)	—	—	—		—		—		—		(6,687)		(6,687)
Other comprehensive income	—	—	—		—		498		—		—		498
Net loss	—	—	—		—		—		—		(93,764)		(93,764)
Balance at March 31, 2026	123,018	(18,759)	$	12,302	$	369,896	$	—	$	(78,733)	$	41,439	$	344,904
Shares issued - stock-based compensation	1,303	—	130		(130)		—		—		—		—
Stock-based compensation expense	—	—	—		1,661		—		—		—		1,661
Treasury stock	—	(370)	—		—		—		(1,985)		—		(1,985)
Dividend distributions ($0.0625 per share)	—	—	—		—		—		—		(6,690)		(6,690)

Net income	—	—	—		—		—		—		42,445		42,445
Balance at June 30, 2026	124,321	(19,129)	$	12,432	$	371,427	$	—	$	(80,718)	$	77,194	$	380,335

See notes to unaudited condensed consolidated financial statements.


	Common Shares Issued	Treasury Shares	Common Stock		Additional Paid-In Capital		Accumulated Other Comprehensive Income (Loss)		Treasury Stock		Retained Earnings		Total
	(in thousands)
Balance at January 1, 2025	122,304	(18,561)	$	12,230	$	362,578	$	(4,962)	$	(78,024)	$	209,761	$	501,583
Shares issued - stock-based compensation	116	—	12		(12)		—		—		—		—
Stock-based compensation expense	—	—	—		1,389		—		—		—		1,389
Treasury stock	—	(40)	—		—		—		(155)		—		(155)
Dividend distributions ($0.0625 per share)	—	—	—		—		—		—		(6,570)		(6,570)
Other comprehensive income	—	—	—		—		117		—		—		117
Net income	—	—	—		—		—		—		7,730		7,730
Balance at March 31, 2025	122,420	(18,601)	$	12,242	$	363,955	$	(4,845)	$	(78,179)	$	210,921	$	504,094
Shares issued - stock-based compensation	598	—	60		(60)		—		—		—		—
Stock-based compensation expense	—	—	—		1,437		—		—		—		1,437
Treasury stock	—	(158)	—		—		—		(554)		—		(554)
Dividend distributions ( $0.0625 per share)	—	—	—		—		—		—		(6,557)		(6,557)
Other comprehensive income	—	—	—		—		4,759		—		—		4,759
Net income	—	—	—		—		—		—		8,380		8,380
Balance at June 30, 2025	123,018	(18,759)	$	12,302	$	365,332	$	(86)	$	(78,733)	$	212,744	$	511,559

See notes to unaudited condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)


	Six Months Ended June 30,
	2026		2025
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(51,319)	$	16,111
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	52,484		58,578
Loss on Canada Assets Divestment	1,202		—
Amortization of deferred financing costs	851		461
Deferred tax benefit	(9,537)		(7,399)
Unrealized foreign exchange loss	432		305
Exploration expense	13,378		—
Stock-based compensation expense	3,021		2,976

Derivative instruments (gain) loss, net	51,861		(326)
Cash settlements received (paid) on matured derivative contracts, net	(32,587)		214


Credit losses and other	844		2


Equipment and other expensed in operations	3,560		2,448
Change in operating assets and liabilities:
Trade receivables, net	16,697		(47,137)
Accounts with joint venture owners, net	(2,970)		(853)
Other receivables	158		31,200
Crude oil inventory	(3,331)		8,180
Premiums paid on commodity derivative contracts	(1,354)		—
Prepayments and other	(2,896)		(1,673)
Value added tax and other receivables	1,373		6,178

Accounts payable	(3,479)		11,212
Foreign income taxes payable	(11,867)		(20,118)

Accrued liabilities and other	7,954		(9,310)
Net cash provided by operating activities	34,475		51,049
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures, including exploration expense	(181,636)		(104,426)
Proceeds from the Canada Assets Divestment	25,474		—
Acquisition of oil and gas properties	—		(3,034)
Net cash used in investing activities	(156,162)		(107,460)
CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from borrowings	117,000		60,000
Dividend distribution	(13,435)		(13,127)
Payments for treasury shares	(1,985)		(709)
Deferred financing costs paid	(2,180)		(6,910)
Payments of finance leases	(6,211)		(6,332)
Net cash provided by financing activities	93,189		32,922
Effects of exchange rate changes on cash	(32)		96
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(28,530)		(23,393)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD	66,963		97,726
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	38,433	$	74,333

See notes to unaudited condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)


	Six Months Ended June 30,
	2026		2025
	(in thousands)
Supplemental disclosure of cash flow information:
Income taxes paid in-kind with crude oil	$	26,737	$	32,263
Interest paid, net of interest capitalized	$	2,834	$	3,160
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	7,614	$	9,491
Recognition of right-of-use finance lease assets and liabilities	$	—	$	2,372
Recognition of right-of-use operating lease assets and liabilities	$	8,058	$	—
Changes in asset retirement obligation	$	77	$	126

See notes to unaudited condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1 . ORGANIZATION AND ACCOUNTING POLICIES

Vaalco Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “Vaalco” or the “Company”) is a Houston, Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and natural gas liquids (“NGLs”) properties. We have a diversified African-focused asset portfolio in Gabon, Egypt, Côte d’Ivoire, Nigeria and Equatorial Guinea, and, prior to the Canada Assets Divestment (defined below), producing properties in Canada.

These unaudited condensed consolidated financial statements (“Financial Statements”) reflect the opinion of management and 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 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 audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025, which includes a summary of the significant accounting policies.

Allowance for credit losses and other – The Company estimates the current expected credit losses based primarily on either an aging analysis or a 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 following table provides an analysis of the change in the aggregate credit loss allowance and other allowances.


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
	(in thousands)

Balance at beginning of period	$	(2,922)	$	(2,527)	$	(2,652)	$	(2,554)
Credit losses and other	(574)		(326)		(844)		(637)
Credit recoveries and other	—		297		—		635


Balance at end of period	$	(3,496)	$	(2,556)	$	(3,496)	$	(2,556)

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

The Company records balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. The Company has previously 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. Beginning during the three months ended March 31, 2026 and effective during such period and for subsequent periods thereafter, the Company changed the presentation of derivative assets and liabilities on the Consolidated Balance Sheets from a gross basis to a net basis by counterparty when a legally enforceable master netting arrangement exists. The Company believes that net presentation better reflects the rights and obligations associated with these derivative instruments. This change affects presentation only and does not affect the recognition, measurement, or classification of the derivative assets and liabilities. It also had no impact on the Company’s consolidated statements of operations, cash flows, or shareholders’ equity. Prior period amounts have been conformed to the current presentation. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the consolidated statements of operations and comprehensive income (loss).

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Fair Value of Derivative Instruments – The following table, set forth by level within the fair value hierarchy, shows the Company’s derivatives that were accounted for at fair value as of June 30, 2026 and December 31, 2025.


		As of June 30, 2026
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Assets
Derivative assets, current	Prepayments and other	$	—	$	2,335	$	—	$	2,335

		$	—	$	2,335	$	—	$	2,335
Liabilities
Derivative liabilities	Accrued liabilities and other	$	—	$	11,262	$	—	$	11,262
		$	—	$	11,262	$	—	$	11,262


		As of December 31, 2025
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Assets
Derivative asset	Prepayments and other	$	—	$	2,846	$	—	$	2,846

		$	—	$	2,846	$	—	$	2,846

The Company’s commodity price derivatives primarily represent crude oil collar contracts and fixed price swap contracts and differential swap contracts. The asset and liability measurements for the Company’s commodity price derivative contracts are determined using Level 2 inputs. The asset and liability values attributable to the Company’s commodity price derivatives were determined based on inputs that include, but are not limited to, the contractual price of the underlying position, current market prices, crude oil forward curves, discount rates, and volatility factors.

See Note 7. Derivatives for further details of the Company’s derivative contracts.

2 . NEW ACCOUNTING STANDARDS

Not Yet Adopted

In November 2024, the FASB issued ASU 2024-03, Accounting Standards Update 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve financial reporting by requiring that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of adopting this ASU on its notes to the consolidated financial statements and processes.

In July 2025, the FASB issued ASU 2025-05, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets. The ASU introduces a practical expedient and, for non-public business entities, an accounting policy election to simplify the application of credit loss guidance to short-term receivables and contract assets by allowing consideration of post-balance-sheet collections. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The Company has elected to not adopt the practical expedient and therefore, the Company, when estimating its credit losses, will continue to consider available information that is relevant to its assessment of the collectability of cash flows, including historical losses, current economic conditions, and reasonable and supportable forecasts. Management will continue to monitor changes in the Company’s portfolio, economic conditions, and future guidance issued by the Financial Accounting Standards Board to determine whether election of the practical expedient would be appropriate in future reporting periods.

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3 . ACQUISITION AND DIVESTMENT

Assumption of Operatorship

In February 2026, the Company became the operator with a 60% working interest in the Kossipo field on the CI-40 Block with a field development plan expected to be completed in the first half of 2027.

Canada Assets Divestment

As of December 31, 2025, the assets and liabilities associated with the Canada Assets Divestment (defined below) were classified as held for sale. The Company recorded an impairment loss of $67.2 million at the time it classified the assets as held for sale to adjust the carrying value of the assets held for sale to their estimated fair value less cost to sell.

On February 4, 2026, the Company entered into an asset purchase agreement to sell all of its operating assets in Canada (the “Canada Assets Divestment”) to a third party purchaser for a purchase price of $24.4 million (C$33.4 million) to be settled in cash, subject to customary post-closing adjustments. The Canada Assets Divestment closed on February 19, 2026 for an adjusted purchase price of $25.5 million (C$34.9 million), subject to customary post-closing adjustments, resulting in a $1.2 million loss on sale of assets recognized in the six months ended June 30, 2026. The sale had an effective date of February 1, 2026.

The net cash proceeds from the divestment were primarily used to fund our capital expenditures and for working capital purposes. The Canada Assets Divestment represents the Company’s complete exit of its Canadian oil and gas operations.

4 . EARNINGS PER SHARE

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
	(in thousands)
Net income (loss) (numerator):
Net income (loss)	$	42,445	$	8,380	$	(51,319)	$	16,111
Income attributable to unvested shares	(1,197)		(100)		(344)		(197)
Numerator for basic	41,248		8,280		(51,663)		15,914
Income attributable to unvested shares	—		—		—		—
Numerator for dilutive	$	41,248	$	8,280	$	(51,663)	$	15,914

Weighted average shares (denominator):
Basic weighted average shares outstanding	104,518		103,936		104,389		103,848
Effect of dilutive securities	125		22		—		24
Diluted weighted average shares outstanding	104,643		103,958		104,389		103,872
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be antidilutive	714		1,312		4,210		1,321

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5 . REVENUE

Production Sharing Contracts

Exploration and production activities of our assets in Gabon, Egypt, Côte d’Ivoire, and Equatorial Guinea are generally governed by PSCs.

Our oil entitlement under the PSCs is generally the sum of cost oil, profit oil and excess cost oil, if applicable. Under the terms of the PSCs, the Company is typically the contractor partner (“Contractor”) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred (“Cost Oil”) and a stipulated share of production after cost recovery (“Profit Oil”).

The Contractor may be obligated to make royalty payments to the host government of each country using a variable percentage based on gross daily production levels. The remaining oil production, after deducting the gross royalty, if any, is split between Cost Oil and Profit Oil. Cost Oil is up to a maximum percentage and is allocated to recover approved operating and capital costs spent on specific projects. Excess Cost Oil, which is Cost Oil less the actual cost recovery, is further shared between the host government and the Contractor. Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale.

Our share of royalties is paid out of the government's share of production. Additionally, the income tax to which the Contractor is subject (“Profit Oil Tax”) is deemed to have been paid to the host government as part of the payment of Profit Oil or is captured in the entitled share of Profit Oil production paid in-kind to the host government, and therefore no additional tax burden is due. Under this arrangement, taxation is based on a set percentage of average daily production volume.

Gabon

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,
	2026		2025		2026		2025
Revenues from customer contracts:	(in thousands)
Sales under the COSPA or COSMA(1)	$	101,142	$	65,984	$	100,974	$	97,434
Gabonese government share of Profit Oil	2,201		1,980		26,738		30,394
Carried interest recoupment	4,241		65		4,241		65
Royalties and other	(15,786)		(9,462)		(18,754)		(17,139)
Net revenues	$	91,798	$	58,567	$	113,199	$	110,754

(1) Crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements (“COSMA” or “COSMAs”).

With respect to the government’s share of Profit Oil, the Etame PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the unaudited 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. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, which is the period in which it lifts the crude oil. As of June 30, 2026 and December 31, 2025, the Company’s Gabon segment had $6.0 million and $18.8 million of foreign income tax payable, respectively.

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Egypt

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Revenues from customer contracts:	(in thousands)
Gross sales	$	86,356	$	55,188	$	152,766	$	112,844
Royalties	(42,748)		(21,752)		(70,058)		(45,339)
Selling costs	(240)		(179)		(424)		(328)
Net revenues	$	43,368	$	33,257	$	82,284	$	67,177

As of June 30, 2026 and December 31, 2025, the Company’s Egypt segment had $1.3 million and $0.3 million of foreign income tax payable, respectively.

Côte d’Ivoire

Revenues from contracts with customers are generated from sales in Côte d’Ivoire pursuant to crude oil sales and purchase agreements and revenues are recognized when a lifting is completed.

The following table presents revenues in Côte d’Ivoire from contracts with customers:


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Revenues from customer contracts:	(in thousands)
Sales under the sales and purchase agreements	$	—	$	353	$	—	$	16,527
Côte d’Ivoire government share of Profit Oil taken in-kind	—		—		—		1,869
Net revenues	$	—	$	353	$	—	$	18,396

Similar to Gabon, the government’s share of Profit Oil attributable to the Company’s equity interest is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. In addition, under the terms of the Côte d’Ivoire PSC, the tax payments to the Ivorian Government are deemed satisfied by its share of the Profit Oil. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, which is the period in which it lifts the crude oil. At both June 30, 2026 and December 31, 2025, the Company’s Cote d’Ivoire segment had $0.3 million of foreign income tax payable.

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Canada

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Revenues from customer contracts:	(in thousands)
Oil revenue	$	—	$	3,751	$	1,744	$	9,076
Gas revenue	—		572		368		1,208
NGL revenue	—		1,259		723		3,019
Other revenue	—		39		27		87
Royalties	—		(666)		(437)		(2,022)
Selling costs	—		(240)		(143)		(473)
Net revenues	$	—	$	4,715	$	2,282	$	10,895

During the six months ended June 30, 2026, the Canada segment revenues include amounts recognized from January 1, 2026 through the closing date of the Canada Assets Divestment.

Information about the Company’s most significant customers

For the three and six months ended June 30, 2026 and 2025, our revenue concentration by major customers is shown in the table below.


	Three Months Ended June 30,		Six Months Ended June 30,
	2026	2025	2026	2025
Gabon	100%	100%	100%	100%
Egypt	100%	100%	100%	100%
Côte d’Ivoire	—%	100%	—%	100%
Canada	—%	59%, 17% and 11%	47%, 16% and 14%	55%, 20% and 15%

6 . CRUDE OIL, NATURAL GAS AND NGLS PROPERTIES AND EQUIPMENT, NET

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


	As of June 30, 2026		As of December 31, 2025
	(in thousands)
Crude oil, natural gas and NGLs properties and equipment, net
Wells, platforms and other production facilities	$	1,301,580	$	1,016,019
Work-in-progress	75,242		214,213
Unproved properties	49,084		52,079
Capitalized equipment, spare parts and other	109,745		84,471
	1,535,651		1,366,782
Accumulated depreciation, depletion, amortization and impairment	(825,998)		(780,687)
Crude oil, natural gas and NGLs properties and equipment, net	$	709,653	$	586,095

At December 31, 2025, the Company classified $31.8 million of net crude oil, natural gas and NGLs properties and equipment, including unproved property costs of $13.1 million, as “Noncurrent asset held for sale” on the Consolidated Balance Sheet.

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Exploration expense

During the three and six months ended June 30, 2026, we incurred exploration expenses of $0.1 million and $22.5 million, respectively, which included the cost of additional seismic data to be used in the Niosi and Guduma blocks, and the costs of an unsuccessful well. During the three and six months ended June 30, 2025, we incurred exploration expenses of $2.5 million attributable to the purchase of seismic data for Block 705 in Côte d’Ivoire.

7 . DERIVATIVES

We have entered into derivative contracts primarily with counterparties that are also lenders under the 2025 RBL Facility (defined below) to hedge price risk associated with a portion of our oil, natural gas and NGLs production. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points. See table below for the list of outstanding contracts as of June 30, 2026:



Settlement Period	Index	Total volumes (Bbls)	Weighted average floor price ($/Bbl)		Weighted average ceiling price ($/Bbl)
Crude oil:
Collars	Dated Brent
2026
July 2026 to September 2026		777,000	$	63.85	$	68.73
October 2026 to December 2026		692,000	$	64.96	$	68.33
2027
January 2027 to March 2027		673,000	$	64.68	$	72.63
April 2027 to June 2027		564,000	$	70.99	$	84.35
July 2027 to September 2027		185,000	$	65.00	$	93.50

Financial Statement Presentation

In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s consolidated balance sheets.

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The following tables summarize the fair value of all outstanding commodity derivative instruments recorded in the Company’s consolidated balance sheets:


(in thousands)	June 30, 2026
Derivative Instrument	Gross Amount		Gross Amount Offset		Net Amount
Derivatives assets:
Commodity derivatives - current	$	2,962	$	(627)	$	2,335

Total derivatives assets	$	2,962	$	(627)	$	2,335

Derivatives liabilities:
Commodity derivatives - current (a)	$	11,889	$	(627)	$	11,262
Total derivatives liabilities	$	11,889	$	(627)	$	11,262
(a) Includes deferred premiums payable of $0.5 million.


(in thousands)	December 31, 2025
Derivative Instrument	Gross Amount		Gross Amount Offset		Net Amount
Derivative assets:
Commodity derivatives - current	$	3,053	$	(207)	$	2,846
Total derivatives assets	$	3,053	$	(207)	$	2,846

Derivatives liabilities:
Commodity derivatives - current	$	207	$	(207)	$	—
Total derivatives liabilities	$	207	$	(207)	$	—

See Note 1. Organization and Accounting Policies for further details on the measurement of our derivative assets at fair value.

The following table sets forth the gain (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	2026		2025		2026		2025
		(in thousands)				(in thousands)
Commodity derivatives	Realized gain (loss), net	$	(25,018)	$	91	$	(39,651)	$	214
	Unrealized gain (loss), net	43,738		309		(12,210)		112
	Derivative instruments gain (loss), net	$	18,720	$	400	$	(51,861)	$	326

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8 . CURRENT ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:


	As of June 30, 2026		As of December 31, 2025
	(in thousands)
Accrued capital expenditures	$	59,224	$	51,339
Accrued accounts payable invoices	25,138		16,320
State oil liability	18,244		18,244
Derivative liabilities	10,739		—
Gabon contractual obligations	7,273		3,858
Accrued wages and other compensation	6,142		6,694
Withholding taxes payable	3,934		1,668



Other	5,130		8,320
Total accrued liabilities and other (a)	$	135,824	$	106,444

(a) The table excludes $0.2 million of current portion of asset retirement obligations associated with assets held for sale as of December 31, 2025.

9 . 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. At June 30, 2026, $10.7 million ($6.3 million, net to Vaalco) of the abandonment fund has been funded 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.

Merged Concession Agreement

The Company is a party to the Merged Concession Agreement with the Egyptian General Petroleum Corporation (“EGPC”) (the “Merged Concession Agreement”). In accordance with the Merged Concession Agreement, the Company was required to make a $10.0 million annual modernization payment to EGPC each year through February 1, 2026. As of December 31, 2025, all modernization payments had been fully settled either through actual cash payments or through the issuance of credit against receivables owed from EGPC.

The Company also has minimum financial work commitments of $50 million per each five-year period of the primary development term, commencing on February 1, 2020 for a total of $150 million over the 15-year license contract term. Through June 30, 2026, the Company's financial work commitments have exceeded the five-year minimum $50 million threshold and any excess carries forward to offset against subsequent five-year commitments.

Drilling Rig Commitment

The Company entered into a bareboat charter agreement (the “Bareboat Charter”) for its Phase Three drilling campaign in Gabon. Pursuant to the Bareboat Charter, the Company also entered into a service agreement with a third party for purposes of maintaining and operating the drilling rig on its behalf. The Bareboat Charter commenced in November 2025 and has a noncancelable period of 300 days plus five single well options. The Bareboat Charter stipulates fixed day rates and other variable payments.

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10 . DEBT

2025 RBL Facility

The Company’s reserves-based facility agreement (the “2025 Facility Agreement”) provides a senior secured reserve-based revolving credit facility (the “2025 RBL Facility”) with maximum aggregate commitments of $300.0 million, subject to certain conditions specified in the 2025 Facility Agreement. The borrowing base amount is calculated pursuant to the 2025 Facility Agreement and redetermined on March 31 and September 30 of each year beginning June 30, 2025 and, in certain circumstances, other interim triggers set out in the 2025 Facility Agreement. In addition, the aggregate commitments are scheduled to reduce semi-annually starting with a $15.8 million reduction on March 31, 2027, and a $35.5 million reduction for each of the subsequent semi-annual periods starting on September 30, 2027.

Effective January 23, 2026, certain existing Lenders (defined below) under the 2025 RBL Facility agreed to increase their initial commitment from $190.0 million to $255.0 million. In addition, on April 28, 2026, certain existing Lenders further increased their commitments to $300.0 million, which is equal to the maximum aggregate commitments permitted under the facility. The increases in commitments were undertaken with the existing accordion feature included in the 2025 RBL Facility.

As of June 30, 2026, the 2025 RBL Facility had $300.0 million of aggregate commitments and $177.0 million of outstanding borrowings, resulting in available borrowing capacity of $123.0 million. As of December 31, 2025, our outstanding borrowing under the 2025 RBL Facility was $60.0 million. Proceeds from our borrowings were primarily used to fund the Baobab FPSO refurbishment and reconnection. The weighted-average interest rate on outstanding borrowings under the 2025 RBL Facility was 10.2% for the six months ended June 30, 2026 and 10.7% from the inception of the 2025 Facility Agreement through December 31, 2025.

In July 2026, the Company borrowed an additional $40.0 million under the 2025 RBL Facility.

Each loan under the 2025 RBL Facility will bear interest at a rate equal to Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (the “Applicable Margin”) of (i) 6.50%, from the date of the 2025 Facility Agreement until the date on which the renovation and repair of the floating production storage and offloading (“FPSO”) tanker facility named Baobab FPSO for use in connection with the development of the Baobab field (the “Baobab FPSO Renovation”) meets certain completion tests defined in the 2025 Facility Agreement and (ii) thereafter, 6.00% until the Final Maturity Date (defined below). We shall pay the accrued interest on the last day of each applicable interest period, which interest period may be, at our option, one, three or six months or such other period as agreed between us and the lenders party to the 2025 Facility Agreement (the “Lenders”).

The loans under the 2025 RBL Facility may be borrowed, repaid, and reborrowed during the term of the 2025 RBL Facility, which will mature on the earlier of (i) March 4, 2031, which is the sixth anniversary of the date of the 2025 Facility Agreement and (ii) the Reserve Tail Date (the “Final Maturity Date”). The Reserve Tail Date is the last day of the calculation period immediately preceding the first calculation period in which the aggregate remaining reserves for all of the borrowing base assets are projected in the then current banking case to be less than 25% of the initial approved reserves.

The 2025 RBL Facility is secured against certain assets of the Company and the other obligors under the 2025 Facility Agreement. The security package includes security interest in the shares of the obligors (other than in the Company), hedging agreements, intercompany loans, insurances, offtake agreements relating to the borrowing base assets and project accounts.

The 2025 Facility Agreement contains certain financial covenants, including that, beginning on June 30, 2025 and then as of each March 31 and September 30 until the Final Maturity Date, the ratio of Total Net Indebtedness to EBITDAX (each defined in the 2025 Facility Agreement) for the trailing 12 months shall not exceed 3.0x. Additionally, following the Baobab FPSO Renovation completion date, the debt service coverage ratio for the 12 months commencing on the day immediately following each March 31 and September 30 (and any interim redetermination date) until the Final Maturity Date shall be at least 1.2:1. The Company also provides a liquidity forecast for the Company and certain of its subsidiaries which shall demonstrate that the total corporate sources equal or exceed the total corporate uses. The liquidity forecast is delivered quarterly during the Baobab FPSO Renovation period and otherwise on each redetermination of the banking case and any proposed distribution.

The Company is required to pay a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount of the difference (if any) by which the borrowing base amount exceeds the then-outstanding amount of loans,

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plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the then-total commitments exceed the higher of the total outstanding amount of loans and the borrowing base amount. The Company is also required to pay customary technical and modeling bank fees, agency fees and security agent fees. The 2025 Facility Agreement also contains customary information covenants as well as affirmative and negative covenants subject to customary thresholds and materiality which include, among others, compliance with laws (including environmental laws, sanctions and anti-corruption laws), delivery of quarterly and annual financial statements and compliance certificates, no change of business, no merger and maintenance of corporate existence, field preservations and related contracts relating to the borrowing base assets, maintenance of insurance, entry into certain derivatives contracts which are regulated by the 2025 Facility Agreement and the hedging policy, restrictions on the incurrence of liens, indebtedness, asset dispositions, acquisitions, restricted payments, entry into offtake agreements and other customary covenants. If the aggregate borrowings exceed 35% of the lower of (a) the available Total Commitments and (b) the applicable borrowing base amount, we are also required to enter into commodity price hedge positions covering certain volumes of anticipated future production set out in the banking case. There are other covenants that make the Company’s ability to pay dividends and to enter into certain acquisition and disposition transactions subject to certain conditions. These covenants are subject to a number of limitations and exceptions.

Additionally, the 2025 Facility Agreement contains customary events of default, including non-payment and borrowing base deficiency, funding shortfall subject to certain liquidity cure rights, breach of financial covenants, misrepresentation, insolvency, changes in ownership or business, litigation, cross default, expropriation of any borrowing base assets, political events, cessation of production and the occurrence of a material adverse effect. The 2025 Facility Agreement also contains events of default related to the failure to complete the Baobab FPSO Renovation by the Baobab FPSO Renovation long stop date determined in the 2025 Facility Agreement and the failure to renew any field license on substantially the same terms three months before the expiration of such field license and if a change of operator occurs. The events of default contain thresholds and remedy periods customary for credit facilities of this nature. If the obligors do not comply with the financial and other covenants relating to non-payment, sanctions, anti-corruption, loans and guarantee or tax in the 2025 Facility Agreement, the Lenders may require immediate payment of all amounts outstanding under the 2025 Facility Agreement and any outstanding unfunded commitments may be terminated. In addition, if any principal amount payable is not paid upon the due date, interest shall accrue on the overdue amount from the due date up to the date of the actual payment at an additional interest rate of 2% per annum, and such interest shall be immediately payable on demand.

As of June 30, 2026 and December 31, 2025, we were in compliance with all of our debt covenants.

Fair Value Measurement

The fair value of the 2025 RBL Facility approximates its respective carrying amount as its interest rate is variable and reflective of market rates. The fair value measurement for the 2025 RBL Facility represents Level 2 inputs.

11 . INCOME TAXES

Vaalco and its domestic subsidiaries file a consolidated U.S. federal income tax return. Certain foreign subsidiaries also file tax returns in their respective local jurisdictions including Canada, Egypt, Equatorial Guinea, Gabon, Côte d’Ivoire and Nigeria.

The foreign taxes payable are attributable to Gabon and Côte d’Ivoire as of June 30, 2026 and 2025.

The Company’s effective tax rate for the three months ended June 30, 2026 and 2025, excluding the impact of discrete items, was 39.06% and 52.91%, respectively. The Company’s effective tax rate for the six months ended June 30, 2026 and 2025, excluding the impact of discrete items, was 39.25% and 58.36%, respectively. For the three and six months ended June 30, 2026 and 2025, the Company’s overall effective tax rate was primarily impacted by tax rates in foreign jurisdictions higher than the U.S. statutory rate and by non-deductible items associated with operations.

For the three months ended June 30, 2026, the income tax expense of $16.8 million includes a $1.0 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, income taxes were $17.8 million for the period. For the six months ended June 30, 2026, the income tax expense of $21.1 million includes a $2.0 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, income taxes were $19.1 million for the period.

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As of June 30, 2026, 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.

In January 2026, the Company received an assessment from the Canada Revenue Agency in connection with an examination. Following the sale of its Canadian assets, the Company elected not to file an objection or pursue other remedies. As a result, the Company reduced its Canadian net operating loss carryforwards and the related valuation allowance carried forward from December 31, 2025. This adjustment did not have a material impact on the Company’s consolidated financial position, results of operations, cash flows, or income tax expense.

12 . OTHER COMPREHENSIVE INCOME (LOSS)

The functional currency of our Canadian segment is the Canadian Dollar. All of the Company’s other comprehensive income arises from the currency translation of its Canadian segment to USD.

The components of accumulated other comprehensive income are as follows:


	Currency Translation Adjustments
	(in thousands)
Balance at December 31, 2025	$	(498)
Release of cumulative translation adjustment due to the Canada Assets Divestment	386
Amounts reclassified from accumulated other comprehensive income (loss)	112


Balance at June 30, 2026	$	—

As previously discussed, the Canada Assets Divestment, which represents the divestment of substantially all of the net assets of our Canada subsidiary, was completed in February 2026. Accordingly, cumulative translation adjustment gains of $0.4 million were reclassified from accumulated other comprehensive loss into earnings and included in the loss on sale of assets in the consolidated statements of operations and comprehensive income (loss).

13 . SEGMENT INFORMATION

The Company’s operations are based in Gabon, Egypt, Côte d’Ivoire, Nigeria, Equatorial Guinea, and, prior to the Canada Assets Divestment, producing properties in Canada. Each of the reportable operating segments are organized and managed based upon geographic location. The Company’s Chief Executive Officer, who is the chief operating decision maker (“CODM”), evaluates segment performance based on the operation of each geographic segment separately primarily based on Operating income (loss) and allocates financial and capital resources for each segment predominantly in the annual budget and forecasting process. The CODM also considers budget-to-actual variances on a quarterly basis for the performance measure when making decisions about allocating capital and personnel to the segments.

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 and are shown in the tables to reconcile the business segments to consolidated totals. No transactions occurred between operating segments. “Other operating income (expense)” below includes those items that are included in Net income (loss) but are not regularly provided to the CODM, or are reported to the CODM but are not considered to be significant segment expenses.

Segment activity of continuing operations for the three and six months ended June 30, 2026 and 2025, as well as long-lived assets and segment assets at June 30, 2026 and December 31, 2025 are as follows:

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	Three Months Ended June 30, 2026
(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Côte d’Ivoire		Corporate and Other		Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	91,798	$	43,368	$	—	$	—	$	—	$	—	$	135,166
Operating costs and expenses:
Production expense	26,696		15,596		—		377		2,801		—		45,470
Exploration expense	60		—		—		—		5		—		65
Depreciation, depletion and amortization	24,369		8,601		—		—		935		367		34,272

General and administrative expense	914		48		—		46		1,005		9,181		11,194
Credit losses and other	376		—		—		197		—		—		573
Total operating costs and expenses	52,415		24,245		—		620		4,746		9,548		91,574

Operating income (loss)	39,383		19,123		—		(620)		(4,746)		(9,548)		43,592
Other income (expense):
Derivative instruments gain, net	—		—		—		—		—		18,720		18,720
Interest income (expense), net	(603)		106		—		—		(1,867)		(386)		(2,750)

Other income (expense), net	(600)		335		—		—		—		(60)		(325)
Total other income (expense), net	(1,203)		441		—		—		(1,867)		18,274		15,645
Income (loss) before income taxes	38,180		19,564		—		(620)		(6,613)		8,726		59,237
Income tax expense (benefit)	15,667		5,929		—		—		(6,208)		1,404		16,792
Net income (loss)	$	22,513	$	13,635	$	—	$	(620)	$	(405)	$	7,322	42,445
Consolidated capital expenditures	$	42,487	$	8,543	$	—	$	41	$	47,636	$	153	$	98,860


	Six Months Ended June 30, 2026
(in thousands)	Gabon		Egypt		Canada (a)		Equatorial Guinea		Côte d’Ivoire		Corporate and Other		Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	113,199	$	82,284	$	2,282	$	—	$	—	$	—	$	197,765
Operating costs and expenses:
Production expense	37,030		30,198		2,040		640		3,941		—		73,849
Exploration expense	22,246		—		—		—		213		—		22,459
Depreciation, depletion and amortization	32,616		17,296		35		—		1,845		692		52,484
Loss on sale of assets	—		—		1,304		—		—		(102)		1,202
General and administrative expense	1,569		107		1		108		1,632		16,053		19,470
Credit losses and other	376		—		22		446		—		—		844
Total operating costs and expenses	93,837		47,601		3,402		1,194		7,631		16,643		170,308

Operating income (loss)	19,362		34,683		(1,120)		(1,194)		(7,631)		(16,643)		27,457
Other income (expense):
Derivative instruments loss, net	—		—		—		—		—		(51,861)		(51,861)
Interest income (expense), net	(1,331)		109		—		—		(2,587)		(640)		(4,449)

Other income (expense), net	(1,171)		(121)		(7)		(2)		95		(153)		(1,359)
Total other expense, net	(2,502)		(12)		(7)		(2)		(2,492)		(52,654)		(57,669)
Income (loss) before income taxes	16,860		34,671		(1,127)		(1,196)		(10,123)		(69,297)		(30,212)
Income tax (benefit) expense	13,290		14,086		—		—		(12,988)		6,719		21,107
Net income (loss)	$	3,570	$	20,585	$	(1,127)	$	(1,196)	$	2,865	$	(76,016)	$	(51,319)
Consolidated capital expenditures	$	65,002	$	10,311	$	128	$	186	$	96,402	$	374	$	172,403

(a) During the six months ended June 30, 2026, the Canada segment revenues include amounts recognized from January 1, 2026 through the closing date of the Canada Assets Divestment.

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	Three Months Ended June 30, 2025
(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Côte d’Ivoire		Corporate and Other		Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	58,568	$	33,257	$	4,715	$	—	$	353	$	—	$	96,893
Operating costs and expenses:
Production expense	23,332		13,130		2,488		386		1,056		1		40,393
Exploration expense	—		—		—		—		2,520		—		2,520
Depreciation, depletion and amortization	14,673		9,220		3,160		—		968		252		28,273
General and administrative expense	202		62		39		86		237		7,870		8,496
Credit losses (recovery) and other	(297)		—		—		326		—		—		29
Total operating costs and expenses	37,910		22,412		5,687		798		4,781		8,123		79,711

Operating income (loss)	20,658		10,845		(972)		(798)		(4,428)		(8,123)		17,182
Other income (expense):
Derivative instruments gain, net	—		—		—		—		—		400		400
Interest expense, net	(835)		(180)		—		—		(1,396)		(161)		(2,572)

Other income (expense), net	(132)		57		430		(1)		116		(117)		353
Total other income (expense), net	(967)		(123)		430		(1)		(1,280)		122		(1,819)
Income (loss) before income taxes	19,691		10,722		(542)		(799)		(5,708)		(8,001)		15,363
Income tax expense (benefit)	5,356		3,343		—		—		(6,139)		4,423		6,983
Net income (loss)	$	14,335	$	7,379	$	(542)	$	(799)	$	431	$	(12,424)	$	8,380
Consolidated capital expenditures	$	9,199	$	7,593	$	210	$	306	$	23,521	$	37	40,866


	Six Months Ended June 30, 2025
(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Côte d'Ivoire		Corporate and Other		Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	110,754	$	67,177	$	10,895	$	—	$	18,396	$	—	$	207,222
Operating costs and expenses:
Production expense	47,655		25,131		4,611		686		7,114		1		85,198
Exploration expense	—		—		—		—		2,520		—		2,520
Depreciation, depletion and amortization	26,094		17,271		6,550		—		8,388		275		58,578
General and administrative expense	446		103		31		150		863		15,955		17,548
Credit losses (recovery) and other	(635)		—		—		637		—		—		2
Total operating costs and expenses	73,560		42,505		11,192		1,473		18,885		16,231		163,846

Operating income (loss)	37,194		24,672		(297)		(1,473)		(489)		(16,231)		43,376
Other income (expense):
Derivative instruments gain, net	—		—		—		—		—		326		326
Interest expense, net	(1,871)		(423)		—		—		(1,287)		(285)		(3,866)

Other income (expense), net	(764)		61		398		(5)		(61)		(288)		(659)
Total other income (expense), net	(2,635)		(362)		398		(5)		(1,348)		(247)		(4,199)
Income (loss) before income taxes	34,559		24,310		101		(1,478)		(1,837)		(16,478)		39,177
Income tax expense (benefit)	14,244		8,530		—		—		(10,234)		10,526		23,066
Net income (loss)	$	20,315	$	15,780	$	101	$	(1,478)	$	8,397	$	(27,004)	$	16,111
Consolidated capital expenditures	$	16,305	$	13,840	$	1,517	$	559	$	59,941	$	19	$	92,181

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(in thousands)	Gabon		Egypt		Canada(a)		Equatorial Guinea		Côte d’Ivoire		Corporate and Other		Total
Long-lived assets:
As of June 30, 2026	$	211,453	$	131,854	$	—	$	11,434	$	350,709	$	4,203	$	709,653
As of December 31, 2025	$	177,030	$	138,839	$	—	$	11,248	$	254,307	$	4,671	$	586,095

(a) At December 31, 2025, the Company classified $31.8 million of net Crude oil, natural gas and NGLs properties as “Noncurrent Assets held for sale” on the Consolidated Balance Sheet.


(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Côte d’Ivoire		Corporate and Other		Total
Total assets:
As of June 30, 2026	$	347,478	$	153,988	$	1,500	$	14,147	$	394,693	$	56,764	$	968,570
As of December 31, 2025	$	315,787	$	182,023	$	35,982	$	13,631	$	283,768	$	82,184	$	913,375

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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”), and may also include forward-looking information within the meaning defined under applicable Canadian securities laws (collectively, “forward-looking statements”), 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:

•the impact of world health events, including any related impact on global demand for crude oil and crude oil prices, potential difficulties in obtaining additional liquidity, when and if needed, disruptions in global supply chains and disruptions to our workforce;

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

•the impact of the wide-ranging policy changes and numerous executive actions issued by the current U.S. presidential administration on topics including international trade, imposition of trade tariffs, energy resources, corporate taxes, global climate change initiatives, employment practices, corporate compliance programs, environmental regulations, as well as other matters;

•the macroeconomic, regulatory or other potential effects of a prolonged U.S. government shutdown;

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

•the discovery, acquisition, development and replacement of crude oil, 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 and our 2025 RBL facility, 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 and natural gas;

•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;

•our limited control over the assets we do not operate;

•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 or tariffs, disruptions in financial credit and other disruptions resulting from geo-political events such as the Russia/Ukraine war, conflicts in the Middle East, including the United States-Israel-Iran war, trade tensions between the U.S. and China and U.S. military operations in Venezuela;

•our ability to enter into new customer contracts;

•changes in customer demand and producers’ supply;

•actions by governments and other significant actors with respect to events occurring in the countries in which we operate;

•actions by our joint venture partners;

•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;

•the anticipated impact on our business and operations of the OBBBA; 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, 2025 (“2025 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 2025 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, African-focused independent energy company with a strong production and reserve portfolio of assets in Gabon, Egypt, Côte d’Ivoire, Equatorial Guinea, Nigeria, and, prior to the Canada Assets Divestment, producing properties in Canada. We are currently engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.

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Business Environment and Outlook

The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment and uncertainties. These factors, and any changes to these factors, among others, could have a material adverse impact on our future revenues and overall profitability. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2025 Form 10-K for further discussion of Trends and Uncertainties.

Commodity Prices – Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts of ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies, and actions taken by foreign oil and gas producing nations, including OPEC+. Changes in oil prices could result in adjustments to capital investment levels and allocation, which impact our production volumes.

Geopolitical Conflict and Other Market Forces – The Company continues to monitor geopolitical developments globally, and specifically in Europe, the Middle East, Africa, and North America, where they have the potential to impact operational continuity and market dynamics. Global markets are also experiencing volatility and uncertainty connected to the Russia-Ukraine war, conflicts in the Middle East, including the United States-Israel-Iran war and the U.S intervention in Venezuela. Additionally, geopolitical tensions and localized disruptions persist in parts of West Africa, where we hold significant producing and development interests, and require ongoing vigilance regarding political, economic, and security risks. The duration and impact of these ongoing armed conflicts, and the potential of these conflicts spreading to more regions are uncertain and could adversely affect the global economy, financial markets, our customers and in turn, us.

U.S. Tariffs and Global Trade Policies – In 2025, the U.S. administration enacted sweeping trade legislation, including significant tariff increases on industrial goods, energy-related equipment, and certain critical minerals, with a stated intent to prioritize domestic manufacturing and energy security. Global trade policy continues to evolve and the ultimate impact of recent developments with respect to U.S. tariffs is unclear. While we do not maintain U.S.-based production assets, our operations on the continent of Africa rely on equipment, services, and materials that are often sourced, engineered, or consolidated through the United States or through U.S.-aligned trading routes. As a result, we may experience increased costs and longer lead times for the procurement and delivery of drilling and production equipment, particularly if suppliers adjust pricing in response to increased duties or if we are required to diversify sourcing channels. These impacts could affect the timing, cost structure and execution risk of certain development activities, especially in frontier offshore environments.

Enactment of the One Big Beautiful Bill Act of 2025 – On July 4, 2025, the budget reconciliation bill known as the One Big Beautiful Bill Act of 2025 (“OBBBA”) was signed into law, which includes significant changes to federal tax law and other regulatory provisions that may impact the Company. Among other provisions, the OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017. The legislation has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027. The impact of provisions effective in 2025 and through the date of this filing is not material and the Company is still assessing the impact of provisions that are not yet effective.

As a company, we remain focused on our overall business strategy to maximize the value of our current resources and expand into new development opportunities across our strategically complementary asset base. We intend to accelerate shareholder returns and increase shareholder value by controlling operating costs and capital expenditures, maximizing reserve recoveries and making disciplined strategic accretive acquisitions that meet our strategic and financial objectives. We believe that our quality portfolio, strong management and technical expertise specific to the markets in which we operate, and our ongoing focus on maintaining a competitive cost structure and disciplined capital allocation framework, position us to achieve our business strategy and navigate a variety of commodity price environments. Over the past several years, we have delivered on our focused strategy and believe we will continue to do so with the organic growth programs across our diversified portfolio over the coming years.

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Recent Operational Updates

Gabon

We successfully drilled and completed the Ebouri-5H development well as part of our ongoing Phase Three Drilling Program, with production commencing in June 2026. Following the completion of operations at the Ebouri platform, the drilling rig was mobilized to the SEENT platform where we spudded the ETBNM-3 gas-supply well. The well is planned as a directionally drilled slant well adjacent to a discovery well and is targeting gas and condensate resources in the Dentale D15 reservoir. The well was successfully brought online and the natural gas produced from this successful well is now being utilized for operational purposes in the field to significantly reduce the costs of higher priced diesel that is currently transported to the field by vessel. We also commenced drilling a second development well at the SEENT platform in late July 2026. Through the remainder of the Phase Three Drilling Program, our objective is to continue growing production volumes and adding proved reserves through the successful execution of our development program.

In addition, the BWE Consortium completed its 3D seismic campaign across the Niosi and Guduma blocks in January 2026. The seismic data processing and interpretation are currently ongoing.

Egypt

The 2026 Egypt drilling program commenced in May 2026 with the drilling of the HE-9 development well, which was completed and brought on production in early June 2026. We subsequently initiated drilling of two additional development wells in June 2026, both of which were successfully completed in July 2026. We are continuing with our drilling program in Egypt in the third quarter of 2026.

We also successfully executed a series of workovers, well interventions, well reactivations, water shut-off treatments, and production optimization activities that are contributing to the organic growth of our production and reserves.

Côte d’Ivoire

Following the completion of its planned dry dock refurbishment in February 2026, the Baobab FPSO returned to Côte d’Ivoire and was successfully reconnected to field infrastructure in early April 2026. Production resumed from all producer wells in June 2026. While production has restarted, the first crude oil lifting is scheduled for August 2026. A drilling rig has been mobilized and the drilling program is expected to start in September 2026. This development campaign is expected to drive meaningful production growth and further unlock the value of the main Baobab field in Block CI-40.

The Company is also the operator of exploration license CI-705 with a 70% working interest. Currently in the first exploration period, subsurface interpretation and prospect maturation continues with the Company and its partners scheduled to make the decision whether to enter into the second phase of the exploration period by year-end 2026.

In February 2026, the Company became the operator with a 60% working interest in the Kossipo field on the CI-40 Block with a field development plan being actively progressed toward completion in the first half of 2027.

Equatorial Guinea

We own a 60% working interest in an undeveloped portion of Block P offshore Equatorial Guinea where we are the designated operator. We have an existing plan of development of the Venus field discovery on Block P, which focuses on key areas of drilling evaluations, facilities design, market inquiries and metocean review. The Company has completed the initial Front End Engineering and Design study that confirmed the viability of the development concept and is currently evaluating alternative technical solutions which may deliver enhanced economic value. Work is progressing towards Final Investment Decision in the fourth quarter of 2026.

Canada

As discussed above, in February 2026, the Company completely exited its Canadian oil and gas operations. Please see Part I, Item 1, Note 3. Acquisition and Disposition to the unaudited condensed consolidated financial statements for further discussion on the sale of the Canada operating assets.

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CAPITAL RESOURCES AND LIQUIDITY

Our primary sources of liquidity have been cash flows from operations, cash on hand and available borrowing capacity under the 2025 RBL Facility, and our primary use of cash has been to fund capital expenditures for development activities. At June 30, 2026, we had unrestricted cash of $30.4 million. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and our 2025 RBL Facility to support our current cash requirements during the next 12 months and beyond, including the drilling programs, dividend payments, Merged Concession Agreement, abandonment funding, 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 or pay dividends, or other strategic transactions depends on operating and economic conditions, some of which are beyond our control. In the event additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, on expected timelines, or at all. We continue to evaluate the use of available cash, including opportunistic acquisitions and other growth initiatives, and assess whether additional liquidity sources, including equity and/or debt financing, would be appropriate to fund such activities.

Cash Flows

Our cash flows for the six months ended June 30, 2026 and 2025 are as follows:


	Six Months Ended June 30,
	2026		2025		Change in 2026 over 2025
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	34,190	$	73,370	$	(39,180)
Net change in operating assets and liabilities	285		(22,321)		22,606
Net cash provided by operating activities	34,475		51,049		$	(16,574)

Net cash used in investing activities	(156,162)		(107,460)		(48,702)

Net cash provided by financing activities	93,189		32,922		60,267
Effects of exchange rate changes on cash	(32)		96		(128)
Net change in cash, cash equivalents and restricted cash	$	(28,530)	$	(23,393)	$	(5,137)

The $16.6 million decrease in net cash provided by operating activities during the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily attributable to cash settlements paid on matured derivative contracts and higher exploration expenses, including the acquisition of seismic data and costs associated with an unsuccessful well. These decreases were partially offset by higher crude oil, natural gas and natural gas liquids sales and favorable changes in working capital and other assets and liabilities.

Net cash used in investing activities during the six months ended June 30, 2026 was primarily attributable to $181.6 million for expenditures associated with the Baobab FPSO refurbishment work and reconnection activities, as well as the development drilling programs in Gabon and Egypt, offset by cash proceeds of $25.5 million from the Canada Assets Divestment. For the six months ended June 30, 2025, cash used in investing activities was due to costs associated with the development drilling programs in Egypt, as well as maintenance, project costs and long lead items for Gabon and Côte d’Ivoire.

Net cash provided by financing activities during the six months ended June 30, 2026 primarily consisted of $117.0 million of proceeds from borrowings under the 2025 RBL Facility, offset by cash outflows of $13.4 million for dividend

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distributions, $2.2 million for deferred financing costs, $2.0 million to satisfy employee withholding tax obligations related to vested equity awards, and $6.2 million of principal payments on finance lease obligations. For the six months ended June 30, 2025, cash used in financing activities primarily included $13.1 million for dividend distributions, $6.9 million of payments for deferred financing costs and $6.3 million of principal payments on our finance leases, offset by $60.0 million in proceeds from borrowing under the 2025 RBL Facility.

2025 Facility Agreement and Available Credit

For information on our 2025 Facility Agreement and available credit, see Part I, Item 1, Note 10. Debt to the unaudited condensed consolidated financial statements.

Merged Concession Agreement

For information on the Merged Concession Agreement, see Part I, Item 1, Note 9. Commitments and Contingencies to the unaudited condensed consolidated financial statements.

Commodity Price Hedging

We actively manage commodity price risk by entering into derivative transactions that help mitigate the impact of volatility in crude oil, NGL and natural gas prices on our cash flows and operating results; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices. We have entered into derivative contracts primarily with counterparties that are also lenders under the 2025 RBL Facility. Our 2025 RBL Facility requires us to enter into commodity price hedge positions establishing certain minimum fixed prices for anticipated future production. See Part I, Item 1, Note 7. Derivatives to the unaudited condensed consolidated financial statements for further discussion.

Cash Requirements

Our material cash requirements generally consist of capital projects, finance and operating leases, dividend payments, Merged Concession Agreement and abandonment funding, each of which is discussed in further detail below.

Capital Projects and Expenditures - For the six months ended June 30, 2026, we had accrual basis capital expenditures of $172.4 million compared to $92.2 million accrual basis capital expenditures for the same period in 2025. Capital spending during the six-month period ended June 30, 2026, primarily reflected development activities associated with the Phase Three drilling campaign in Gabon, refurbishment and reconnection activities relating to the FPSO in Côte d’Ivoire, expenditures associated with an unsuccessful exploration well in Gabon and costs incurred in connection with the 3D seismic campaign across the Niosi and Guduma blocks.

See “Recent Operational Updates” above for additional information regarding our capital projects.

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 extension of the Etame PSC, 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. At June 30, 2026, 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.

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 a helicopter, warehouse and storage facilities, equipment and financing lease agreements for the FSO, generators and turbines used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations in Canada and Egypt. The annual costs of these leases are significant to us.

Merged Concession Agreement - Under the Merged Concession Agreement, we have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020. Through June 30, 2026, our financial work commitments have exceeded the five-year minimum $50 million

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threshold and any excess carries forward to offset against subsequent five-year commitments. See Part I, Item 1, Note 9. Commitments and Contingencies to the unaudited condensed consolidated financial statements for additional information.

Drilling Rig Commitment - The Company entered into the Bareboat Charter for its Phase Three drilling campaign in Gabon. Pursuant to the Bareboat Charter, the Company also entered into a service agreement with a third party for purposes of maintaining and operating the drilling rig on its behalf. The Bareboat Charter and the service agreement commenced in November 2025 and have a noncancelable period of 300 days plus five single well options. The Bareboat Charter and the service agreement stipulate fixed day rates and other variable payments.

BWE Consortium - We are a member of the BWE Consortium that was awarded the licenses for the Niosi Marin and the Guduma Marin exploration blocks in Gabon. These licenses are covered by PSCs entered into with the Gabonese Government. These PSCs 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 3D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. Under the terms of the BWE Consortium PSC, the Company holds a 37.5% non-operating working interest in these licenses.

Dividend Policy - Our Board of Directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter, which commenced in the first quarter of 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.

Quarterly Cash Dividends

The Company paid a quarterly cash dividend of $0.0625 per share of common stock for the second quarter of 2026 ($0.25 annualized) on June 26, 2026 to stockholders of record at the close of business on May 22, 2026. The Company also announced its next quarterly cash dividend of $0.0625 per share of common stock for the third quarter of 2026 ($0.25 annualized) to be paid on September 22, 2026 to stockholders of record at the close of business on August 21, 2026.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

There have been no material changes to our critical accounting policies and estimates subsequent to December 31, 2025. For a discussion of the Company's critical accounting policies for the fiscal year ended December 31, 2025, please see our 2025 Form 10-K.

NEW ACCOUNTING STANDARDS

See Part I, Item 1, Note 2. New Accounting Standards to the unaudited condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2026 Compared to the Three Months Ended June 30, 2025

Net income for the three months ended June 30, 2026 was $42.4 million compared to a net income of $8.4 million during the same period in 2025. See discussion below for changes in revenues and expenses.

Crude oil, natural gas and NGLs revenues increased $38.3 million, or approximately 40%, to $135.2 million during the three months ended June 30, 2026 from $96.9 million during the same period in 2025. The increase in revenue is primarily attributable to higher realized sales prices per barrel, partially offset by a slight decline in sales volumes.

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	Three Months Ended June 30,				Increase/(Decrease)
	2026		2025
	(in thousands)
Net crude oil, natural gas, and NGLs sales volume (MBoe)	1,621		1,765		(144)
Average crude oil, natural gas and NGLs sales price (per Boe)	$	80.77	$	54.87	$	25.90
Average Dated Brent spot price* ($/Bbl)	102.63		$	68.07	$	34.56

Net crude oil, natural gas, and NGLs revenue	$	135,166	$	96,893	$	38,273

Operating costs and expenses:
Production expense	45,470		40,393		5,077
Exploration expense	65		2,520		(2,455)
Depreciation, depletion and amortization	34,272		28,273		5,999
General and administrative expense	11,194		8,496		2,698
Credit losses and other	573		29		544
Total operating costs and expenses	91,574		79,711		11,863

Operating income	43,592		17,182		26,410
Other income (expense), net	15,645		(1,819)		17,464
Income (loss) before income taxes	59,237		15,363		43,874
Income tax expense	16,792		6,983		9,809
Net income	$	42,445	$	8,380	$	34,065

Crude oil, natural gas and NGLs revenues:

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. Total revenue from our Gabon segment was $91.8 million during the three months ended June 30, 2026, an increase of $33.2 million from the $58.6 million of revenue reported during the three months ended June 30, 2025. The increase in revenues is primarily due to a higher average realized sales price received in Gabon of $92.31 per Bbl for the three months ended June 30, 2026 compared to the $65.02 per Bbl average realized sales price received during the same period in 2025. Sales volumes also slightly increased from the 900 MBbls reported during the second quarter of 2025 to 948 MBbls for the three months ended June 30, 2026. Gabon’s share of crude oil inventory, excluding royalty barrels, was approximately 125 MBbls and 55 MBbls at June 30, 2026 and 2025, respectively.

Egypt

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, through EGPC. During the three months ended June 30, 2026, the oil sold in Egypt was through direct sales to EGPC. Revenue from our Egypt segment increased to $43.4 million during the three months ended June 30, 2026 from $33.3 million during the comparable period in 2025. The increase in revenues was primarily driven by a higher average realized sales price, which increased to $64.50 per Bbl from $48.01 per Bbl in the same period in the prior year, partially offset by lower sales volumes of 672 MBbls compared to 693 MBbls during the three months ended June 30, 2025.

Côte d’Ivoire

Crude oil sales in Côte d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world. As previously discussed, the Baobab FPSO ceased production in January 2025 to undergo a planned refurbishment which was completed in April 2026. The FPSO was reconnected to field infrastructure and production resumed from all producing wells. While production has restarted, the first crude oil lifting is scheduled for August 2026. As such, there were no revenues from the Company’s Côte d’Ivoire

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segment during the three months ended June 30, 2026. Revenues during the three months ended June 30, 2025 were $0.4 million. Côte d’Ivoire’s share of crude oil inventory was approximately 106 MBbls at June 30, 2026.

Canada

Prior to the Canada Assets Divestment, crude oil sales in Canada were normally sold through pipelines to a third party. During the three months ended June 30, 2025, the Company’s Canadian segment contributed $4.7 million of revenue based on sales volumes of 172 MBoe and an average realized sales price received of $27.35 per Boe.

Production expenses increased $5.1 million, or approximately 13%, for the three months ended June 30, 2026 to $45.5 million from $40.4 million for the same period in the prior year. The increase was primarily attributable to higher production expenses in our Gabon and Egypt segments, offset by lower production expenses resulting from the Canada Assets Divestment and the change in oil inventory adjustments in Cote d’Ivoire. Production expenses associated with unsold crude oil inventory are capitalized and included in inventory, which are then subsequently expensed when oil inventory is sold. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended June 30, 2026 increased to $28.05 per barrel from $22.85 per barrel for the three months ended June 30, 2025.

Exploration expense for the three months ended June 30, 2026 of $0.1 million was attributable to expenses related to the Niosi and Guduma blocks in Gabon. Exploration expenses for three months ended June 30, 2025 were $2.5 million, which were attributable to the purchase of seismic data for Block 705 in Côte d’Ivoire.

Depreciation, depletion and amortization costs increased by $6.0 million, or approximately 21%, for the three months ended June 30, 2026 to $34.3 million from $28.3 million during the same period in 2025. The increase in depreciation, depletion and amortization expense is primarily related to the higher depletable costs in Gabon, partially offset by a decrease in depletable costs as a result of the Canada Assets Divestment.

General and administrative expenses increased by $2.7 million, or 32%, for the three months ended June 30, 2026 to $11.2 million from $8.5 million during the same period in 2025. The increase in general and administrative expenses was primarily a result of higher legal and professional service fees, which included approximately $1.9 million of non-recurring costs associated with business development activities.

Credit losses and other increased by approximately $0.5 million for the three months ended June 30, 2026 compared to the same period in 2025. The increase in credit losses and other is primarily attributable to allowance charges related to other receivables.

Derivative instruments gain (loss), net is attributable to our swaps and collars as discussed in Part I, Item 1, Note 7. Derivatives to the unaudited condensed consolidated financial statements. During the three months ended June 30, 2026, we recognized a net derivative gain on commodity derivative contracts of $18.7 million compared to a net derivative gain of $0.4 million during the same period in 2025. The derivative gain for the three months ended June 30, 2026 is a result of the decrease 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, 2026. Our derivative instruments currently cover a portion of our oil production through September 2027.

Interest expense, net was $2.7 million for the three months ended June 30, 2026 compared to an expense of $2.6 million during the same period in 2025. The increase in net interest expense for the three months ended June 30, 2026 primarily resulted from an increase in our amortization of debt issue costs, commitment fees incurred and interest incurred on our borrowing under the 2025 RBL Facility, partially offset by interest income.

Other income (expense), net was a net expense of $0.3 million for the three months ended June 30, 2026 compared to a net income of $0.4 million during the same period in 2025. Other income (expense), net, normally consists primarily of foreign currency gains and losses.

Income tax expense for the three months ended June 30, 2026 was $16.8 million, which includes a $1.0 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, income taxes were $17.8 million for the period. Income tax expense for the three months ended June 30, 2025 was an expense of $7.0 million, which includes a $3.1 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, current income taxes were $10.1 million for the period.

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Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025

Net loss for the six months ended June 30, 2026 was $51.3 million compared to a net income of $16.1 million during the same period in 2025. See discussion below for changes in revenues and expenses.

Crude oil, natural gas and NGLs revenues decreased $9.4 million, or approximately 5%, to $197.8 million during the six months ended June 30, 2026 from $207.2 million during the same period in 2025. The revenue decrease is attributed to lower sales volumes primarily in Côte d’Ivoire and Canada, partially offset by higher average realized sales prices per barrel.


	Six Months Ended June 30,				Increase/(Decrease)
	2026		2025
	(in thousands)
Net crude oil, natural gas, and NGLs sales volume (MBoe)	2,715		3,481		(766)
Average crude oil, natural gas and NGLs sales price (per Boe)	$	71.28	$	59.50	$	11.78
Average Dated Brent spot price* ($/Bbl)	$	91.50	$	72.03	$	19.47

Net crude oil, natural gas, and NGLs revenue	$	197,765	$	207,222	$	(9,457)

Operating costs and expenses:
Production expense	73,849		85,198		(11,349)
Exploration expense	22,459		2,520		19,939
Depreciation, depletion and amortization	52,484		58,578		(6,094)
Loss on sale of assets	1,202		—		1,202
General and administrative expense	19,470		17,548		1,922
Credit losses and other	844		2		842
Total operating costs and expenses	170,308		163,846		6,462

Operating income	27,457		43,376		(15,919)
Other expense, net	(57,669)		(4,199)		(53,470)
Income (loss) before income taxes	(30,212)		39,177		(69,389)
Income tax expense	21,107		23,066		(1,959)
Net income (loss)	$	(51,319)	$	16,111	$	(67,430)

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

Crude oil, natural gas and NGLs revenues:

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. Total revenues from our Gabon segment were $113.2 million during the six months ended June 30, 2026, an increase of $2.4 million from the $110.8 million reported during the six months ended June 30, 2025. The increase in revenues is primarily due to the higher average realized sales price received in Gabon of $85.71 per Bbl for the six months ended June 30, 2026 compared to $71.04 per Bbl average realized sales price received during the same period in 2025. The increase in sales was partially offset by lower sales volumes of 1,271 MBbls for the six months ended June 30, 2026 compared to 1,558 MBbls reported during the same period of 2025. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 125 MBbls and 55 MBbls at June 30, 2026 and 2025, respectively.

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Egypt

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, through EGPC. During the six months ended June 30, 2026, the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contributed $82.3 million of revenue to the Company’s total revenue for the six months ended June 30, 2026, which is $15.1 million higher than the $67.2 million of revenue reported during the six months ended June 30, 2025. The increase in revenues was primarily due to the increase in average realized sales price from $50.34 per Bbl during the six months ended June 30, 2025 to $60.49 per Bbl during the same period in 2026, as well as the slight increase in sales volumes from 1,334 MBbls to 1,360 MBbls.

Côte d’Ivoire

Crude oil sales in Côte d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world. As previously discussed, following the completion of its planned dry dock refurbishment in February 2026, the Baobab FPSO returned to Côte d’Ivoire and was successfully reconnected to field infrastructure in early April 2026. While production has restarted, the first crude oil lifting is scheduled for August 2026. As such, there were no revenues from the Côte d’Ivoire segment for the six months ended June 30, 2026. The Côte d’Ivoire segment reported revenues of $18.4 million during the six months ended June 30, 2025 with total sales volumes of 238 MBbls and an average realized sales price received of $77.36 per Bbl. Côte d’Ivoire’s share of crude oil inventory was approximately 106 MBbls at June 30, 2026.

Canada

Prior to the Canada Assets Divestment, crude oil production from our Canadian operations was typically sold to third parties through pipeline transportation arrangements. During the six months ended June 30, 2026, revenues from our Canada segment reflect production sold from January 1, 2026 through the closing date of the Canada Assets Divestment. For this period, the Canada segment generated revenues of $2.3 million and reported sales volumes of 83 MBoe, with an average realized sales price of $27.34 per Boe. During six months ended June 30, 2025, we recorded revenues of $10.9 million on sales volumes of 351 MBoe and an average realized sales price received of $31.04 per Boe.

Production expenses decreased $11.4 million for the six months ended June 30, 2026 to $73.8 million from $85.2 million for the same period in the prior year. The decrease in production expenses was primarily driven by lower expenses in Gabon and Cote d’Ivoire mainly due to the change in oil inventory adjustments. Our production expenses also decreased as a result of the Canada Assets Divestment. In addition, we incurred non-recurring costs during the same period in the prior year mainly due to government audit settlements. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the six months ended June 30, 2026 increased to $27.18 per barrel from $24.43 per barrel for the six months ended June 30, 2025.

Exploration expense for the six months ended June 30, 2026 of $22.5 million included the cost of additional seismic data for the Niosi and Guduma blocks, and the costs of an unsuccessful well in Gabon. Exploration expense for the six months ended June 30, 2025 was $2.5 million which was attributable to the purchase of seismic data for Block 705 in Côte d’Ivoire.

Depreciation, depletion and amortization costs decreased $6.1 million, or approximately 10%, for the six months ended June 30, 2026 to $52.5 million from $58.6 million during the same period in 2025. The decrease in depreciation, depletion and amortization expense is due primarily to the Canada Assets Divestment completed in February 2026 as well as due to lower production volumes in Côte d’Ivoire, offset by higher depletable costs in Gabon.

Loss on asset divestment of $1.2 million for the six months ended June 30, 2026 was attributable to the Canada Assets Divestment, which closed in February 2026.

General and administrative expenses increased $2.0 million, or 11%, for the six months ended June 30, 2026 to $19.5 million from $17.5 million during the same period in 2025 driven largely by an increase in legal and professional service fees, which included approximately $1.9 million of non-recurring costs associated with business development activities.

Credit losses and other increased by approximately $0.8 million during the six months ended June 30, 2026 compared to the same period in 2025 primarily due to allowance charges related to receivables from joint venture partners and other receivables.

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Derivative instruments loss, net is attributable to our swaps and collars as discussed in Part I, Item 1, Note 7. Derivatives to the unaudited condensed consolidated financial statements. We recorded a $51.9 million net loss on derivative instruments for the six months ended June 30, 2026, which included an unrealized loss of $12.2 million related to the change in fair value of our commodity derivative contracts primarily driven by an increase in the futures curve for forecasted commodity prices and a realized loss of $39.7 million on matured commodity derivative contracts. We recognized a net gain on derivative instruments of $0.3 million during the same period in 2025. The increase in derivative losses was primarily due to a higher volume of outstanding derivative contracts entered into for the six months ended June 30, 2026 compared to the same period in 2025. Our derivative instruments currently cover a portion of our crude oil production through September 2027.

Interest expense, net was $4.4 million for the six months ended June 30, 2026 compared to $3.9 million during the same period in 2025. The increase in net interest expense for the six months ended June 30, 2026 primarily resulted from an increase in our amortization of debt issue costs, commitment fees incurred and interest incurred on our borrowings under the 2025 RBL Facility, partially offset by interest income.

Other income (expense), net was an expense of $1.4 million and $0.7 million for the six months ended June 30, 2026 and 2025, respectively. Other income (expense), net, primarily consists of foreign currency gains and losses.

Income tax expense for the six months ended June 30, 2026 was $21.1 million, which includes a $2.0 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, income taxes were $19.1 million for the period. Income tax expense for the six months ended June 30, 2025 was $23.1 million, which includes a $2.4 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, current income taxes were $25.4 million for the period.

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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 (the “CFA” 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, 2026, we had net monetary liabilities of $103.2 million (XAF $59.3 billion) denominated in XAF. At June 30, 2026, we estimate that a 10% weakening of the CFA relative to the U.S. dollar would result in a $9.4 million reduction in the value of these net liabilities. For the six months ended June 30, 2026, we had expenditures of approximately $38.6 million net to Vaalco, denominated in XAF.

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. At June 30, 2026, we estimate that a 10% increase in the value of the Egyptian pound against the U.S. dollar would increase the U.S. dollar value of net liabilities for the six months ended June 30, 2026 by $4.3 million. Conversely, a 10% decrease in the value of the Egyptian pound against the U.S. dollar would decrease the U.S. dollar value of net liabilities for the six months ended June 30, 2026 by $3.5 million.

In Côte d’Ivoire, although our revenues and most expenditures are denominated in U.S. dollars, fluctuations in local currency exchange rates may indirectly affect the cost of services, labor, and materials incurred by the operator on our behalf.

We maintain nominal balances of British Pounds Sterling to pay in-country costs incurred in operating our London office. Foreign exchange risk on these funds is not considered material.

We do not utilize derivative instruments to manage foreign exchange risk.

COUNTERPARTY RISK

We are exposed to market risk on our open derivative instruments related to potential nonperformance by our counterparties. 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, natural gas and NGLs production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil, natural gas and NGLs have been volatile and unpredictable in recent years, and this volatility may continue. Sustained low crude oil, natural gas and NGLs prices or a resumption of the decreases in crude oil, natural gas and NGLs prices could

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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.

At June 30, 2026, the Company had open commodity derivative contracts covering our anticipated future production as follows:


Settlement Period	Index	Total volumes (Bbls)	Weighted average floor price ($/Bbl)		Weighted average ceiling price ($/Bbl)
Crude oil:


Collars	Dated Brent
2026
July 2026 to September 2026		777,000	$	63.85	$	68.73
October 2026 to December 2026		692,000	$	64.96	$	68.33
2027
January 2027 to March 2027		673,000	$	64.68	$	72.63
April 2027 to June 2027		564,000	$	70.99	$	84.35
July 2027 to September 2027		185,000	$	65.00	$	93.50

The table below presents commodity swaps entered into subsequent to June 30, 2026.


Settlement Period	Index	Total volumes (Bbls)	Weighted average floor price ($/Bbl)		Weighted average ceiling price ($/Bbl)		Weighted average deferred premium ($/Bbl)
Crude oil:
2027
Collars	Dated Brent

January 2027 to March 2027		60,000	$	65.00	$	102.70	$	—
April 2027 to June 2027		180,000	$	65.00	$	97.82	$	—
July 2027 to September 2027		220,000	$	70.00	$	85.32	$	—

Puts
July 2027 to September 2027		60,000	$	65.00	$	—	$	5.20

Oil and gas properties are assessed for impairment annually as well as whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved and probable reserves, estimated future commodity prices, future production estimates, and anticipated capital and operating expenditures, using a commensurate discount rate. Unfavorable changes in any of these assumptions could result in a reduction in undiscounted future cash flows and could indicate property impairment. Uncertainties related to the primary assumptions could affect the timing of an impairment. In most cases, the assumption that generates the most variability in undiscounted future net cash flows is future oil and gas prices. We observed volatility in commodity prices during the six months ended June 30, 2026; however, no triggering events were identified and therefore no impairment was recorded at June 30, 2026.

If crude oil sales were to remain constant at the most recent annual sales volumes, a $5 per Bbl decrease in crude oil price would decrease our revenues and operating income or increase our operating loss for the six months ended June 30, 2026 as follows:

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	2026 Sales Volumes (Mboe)	Decrease in Revenues (In Millions)		Decrease in Operating Income (Increase in Operating Loss) (In Millions)
Gabon	1,271	$	6.4	$	5.7
Egypt	1,361	$	6.8	$	4.0
Côte d’Ivoire	—	$	—	$	—
Canada	83	$	0.4	$	0.3
Consolidated	2,715

With respect to our crude oil sales in Gabon, Egypt and Côte d’Ivoire, the prices received are based on Dated Brent prices plus or minus a differential. With respect to our crude oil and NGLs sales in Canada, prior to the Canadian Assets Divestment, the prices received are/were based on NYMEX WTI (West Texas Intermediate) prices plus or minus a differential. Natural gas sales are/were based on the Canadian index price whose price is based, in part, on the NYMEX Henry Hub Natural Gas futures contracts. Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government. 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.

Exploration and production activities of our assets in Gabon, Egypt, Côte d’Ivoire, and Equatorial Guinea are generally governed by PSCs. 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”. 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.

INTEREST RATE RISK

As of June 30, 2026, our primary exposure to interest rate risk resulted from our $177.0 million of outstanding borrowings under our 2025 RBL Facility. The borrowing accrues interest at a rate equal to Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin. During the six months ended June 30, 2026, interest expense was calculated based on the weighted average SOFR of 3.7% plus the applicable margin of 6.5%. We currently do not hedge our interest rate exposure. We estimate that a 10% increase in the applicable average interest rates during the time from the date the debt was drawn through June 30, 2026 would have resulted in an increase in interest expense of $0.3 million. Additionally, changes in market interest rates could impact interest costs associated with any future indebtedness.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer (“CEO”) and principal financial officer (“CFO”), to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures. Our management, including our CEO and CFO, has evaluated the effectiveness of our disclosure controls and procedures pursuant to Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this report. Based on their evaluation as of June 30, 2026, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal control over financial reporting during the three months ended June 30, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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. While we cannot predict the occurrence or outcome of these proceedings with certainty, it is management’s opinion that all claims and litigation we are currently involved in are not likely to have a material adverse effect on our unaudited condensed consolidated financial position, cash flows or results of operations.

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 2025 Form 10-K. There have been no material changes in our risk factors from those described in our 2025 Form 10-K.

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

There were no sales of unregistered securities during the three months ended June 30, 2026 that were not previously reported on a Current Report on Form 8-K.

Issuer Purchases of Equity Securities

The following table contains the details related to the purchases of common stock by the Company during the three months ended June 30, 2026:


Period	Total Number of Shares Purchased (1)	Weighted-average Price Paid per Share
April 1, 2026 to April 30, 2026	—	—
May 1, 2026 to May 31, 2026	—	—
June 1, 2026 to June 30, 2026	260,634	$5.40

(1) Shares acquired from holders of restricted stock to satisfy tax-withholding obligations in connection with vesting of such restricted stock.

ITEM 5. OTHER INFORMATION

10b5-1 Trading Arrangements

During the three months ended June 30, 2026, 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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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).
10.1			Global Confirmation Deed, dated April 28, 2026, by and among, Vaalco Energy, Inc.,as the Parent, the entities listed therein, as the Borrowers, Guarantors and/or Security Grantor, The Standard Bank of South Africa Limited (acting through its Corporate and Investment Banking Division), as the Agent, The Standard Bank of South Africa Limited (acting through its Corporate and Investment Banking Division), as the Onshore (Gabon) Security Agent, The Standard Bank of South Africa Limited (acting through its Corporate and Investment Banking Division), as the Offshore Security Agent and HSBC Bank Egypt S.A.E., as the Onshore (Egypt) Security Agent (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on May 11, 2026, and incorporated herein by reference).
10.2*			2026 Form of Performance RSA Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 9, 2026, and incorporated herein by reference).
10.3*			2026 Form of Time-based RSA Agreement (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 9, 2026, and incorporated herein by reference).
10.4*			2026 Form of RSU Award Agreement (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on June 9, 2026, and incorporated herein by reference).
10.5*			Amendment No. 3 to the VAALCO Energy, Inc. 2020 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 4, 2026, 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

Table of Contents

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)