November 10, 2025 - 10-Q: Quarterly report [Sections 13 or 15(d)]

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________

FORM 10-Q

______________________

(Mark One)


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

For the quarterly period ended September 30, 2025


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 November 4, 2025, there were outstanding 104,258,253 shares of common stock, $0.10 par value per share, of the registrant.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets September 30, 2025 and December 31, 2024			2
Condensed Consolidated Statements of Operations and Comprehensive Income Three and Nine Months Ended September 30, 2025 and 2024			3
Condensed Consolidated Statements of Shareholders’ Equity Three and Nine Months Ended September 30, 2025 and 2024			4
Condensed Consolidated Statements of Cash Flows Nine Months Ended S eptember 30 , 2025 and 2024			5
Notes to Condensed Consolidated Financial Statements (unaudited)			7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			21
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			35
ITEM 4. CONTROLS AND PROCEDURES			37
PART II. OTHER INFORMATION			38
ITEM 1. LEGAL PROCEEDINGS			38
ITEM 1A. RISK FACTORS			39
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			39
ITEM 5. OTHER INFORMATION			39
ITEM 6. EXHIBITS			40

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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)


	As of September 30, 2025		As of December 31, 2024
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	23,984	$	82,650
Restricted cash	203		143
Receivables:
Trade, net of allowances for credit loss and other of $0.2 million and $0.2 million, respectively	109,473		94,778
Accounts with joint venture owners, net of allowance for credit losses of $2.5 million and $1.5 million, respectively	6,665		179
Egypt receivables and other	2,726		35,763
Crude oil inventory	8,958		9,441
Prepayments and other	21,729		14,973
Total current assets	173,738		237,927
Crude oil, natural gas and NGLs properties and equipment, net	623,736		538,103
Other noncurrent assets:
Restricted cash	1,659		8,665
Value added tax and other receivables, net of allowances for credit loss and other of $0.4 million and $0.8 million, respectively	6,550		10,094
Right of use operating lease assets	14,364		17,254
Right of use finance lease assets	72,031		79,849
Deferred tax assets	44,304		55,581
Abandonment funding	6,268		6,268
Other long-term assets	7,783		1,209
Total assets	$	950,433	$	954,950
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	17,007	$	11,756
Accounts with joint venture owners	1,489		3,324
Accrued liabilities and other	107,317		107,710
Operating lease liabilities - current portion	4,002		3,512
Finance lease liabilities - current portion	12,649		13,383
Foreign income taxes payable	23,774		42,043
Total current liabilities	166,238		181,728
Asset retirement obligations	84,259		78,592
Operating lease liabilities - net of current portion	10,862		13,903
Finance lease liabilities - net of current portion	60,235		67,377
Deferred tax liabilities	62,966		93,904
Long-term debt	60,000		—
Other long-term liabilities	—		17,863
Total liabilities	444,560		453,367
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, $25 par value; 500,000 shares authorized, none issued	—		—
Common stock,$0.10 par value; 160,000,000 shares authorized, 123,017,656 and 122,304,124 shares issued, 104,258,253 and 103,743,163 shares outstanding, respectively	12,302		12,230
Additional paid-in capital	367,023		362,578
Accumulated other comprehensive loss	(1,885)		(4,962)
Less treasury stock, 18,759,403 and 18,560,931 shares, respectively, at cost	(78,733)		(78,024)
Retained earnings	207,166		209,761
Total shareholders' equity	505,873		501,583
Total liabilities and shareholders' equity	$	950,433	$	954,950

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 (Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(in thousands, except per share amounts)
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	61,007	$	140,334	$	268,230	$	357,267
Operating costs and expenses:
Production expense	29,872		42,324		115,070		126,859

Exploration expense	353		—		2,873		48
Depreciation, depletion and amortization	20,555		47,031		79,133		105,987

General and administrative expense	8,845		6,929		26,393		21,230
Credit losses and other	484		69		485		5,222
Total operating costs and expenses	60,109		96,353		223,954		259,346
Other operating income, net	—		102		—		68
Operating income	898		44,083		44,276		97,989
Other income (expense):
Derivative instruments gain (loss), net	(1,093)		210		(767)		(380)
Interest expense, net	(2,333)		(588)		(6,199)		(2,640)
Bargain purchase gain	—		—		—		19,898
Other income (expense), net	33		(141)		(628)		(3,925)
Total other income (expense), net	(3,393)		(519)		(7,594)		12,953
Income (loss) before income taxes	(2,495)		43,564		36,682		110,942
Income tax expense (benefit)	(3,596)		32,574		19,470		64,115
Net income	$	1,101	$	10,990	$	17,212	$	46,827
Other comprehensive income (loss)
Currency translation adjustments	(1,799)		1,655		3,077		(1,867)
Comprehensive income (loss)	$	(698)	$	12,645	$	20,289	$	44,960

Basic net income per share:
Net income per share	$	0.01	$	0.10	$	0.16	$	0.45
Basic weighted average shares outstanding	104,258		103,743		103,986		103,644
Diluted net income per share:
Net income per share	$	0.01	$	0.10	$	0.16	$	0.45
Diluted weighted average shares outstanding	104,283		103,842		104,010		103,728

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, 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	—	—	—		—		—		—		(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	—	—	—		—		—		—		(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

Stock-based compensation expense	—	—	—		1,691		—		—		—		1,691

Dividend distributions	—	—	—		—		—		—		(6,679)		(6,679)
Other comprehensive loss	—	—	—		—		(1,799)		—		—		(1,799)
Net income	—	—	—		—		—		—		1,101		1,101
Balance at September 30, 2025	123,018	(18,759)	$	12,302	$	367,023	$	(1,885)	$	(78,733)	$	207,166	$	505,873

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, 2024	121,398	(17,051)	$	12,140	$	357,498	$	2,880	$	(71,222)	$	177,486	$	478,782
Shares issued - stock-based compensation	543	—	54		393		—		—		—		447
Stock-based compensation expense	—	—	—		936		—		—		—		936
Treasury stock	—	(1,434)	—		—		—		(6,344)		—		(6,344)
Dividend distributions	—	—	—		—		—		—		(6,463)		(6,463)
Other comprehensive loss	—	—	—		—		(2,454)		—		—		(2,454)
Net income	—	—	—		—		—		—		7,686		7,686
Balance at March 31, 2024	121,941	(18,485)	$	12,194	$	358,827	$	426	$	(77,566)	$	178,709	$	472,590
Shares issued - stock-based compensation	364	—	36		(36)		—		—		—		—
Stock-based compensation expense	—	—	—		1,012		—		—		—		1,012
Treasury stock	—	(76)	—		—		—		(458)		—		(458)
Dividend distributions	—	—	—		—		—		—		(6,579)		(6,579)
Other comprehensive loss	—	—	—		—		(1,068)		—		—		(1,068)
Net income	—	—	—		—		—		—		28,151		28,151
Balance at June 30, 2024	122,305	(18,561)	12,230		$	359,803	(642)		$	(78,024)	200,281		$	493,648

Stock-based compensation expense	—	—	—		1,344		—		—		—		1,344

Dividend distributions	—	—	—		—		—		—		(6,605)		(6,605)
Other comprehensive loss	—	—	—		—		1,655		—		—		1,655
Net income	—	—	—		—		—		—		10,990		10,990
Balance at September 30, 2024	122,305	(18,561)	$	12,230	$	361,147	$	1,013	$	(78,024)	$	204,666	$	501,032

See notes to unaudited condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)


	Nine Months Ended September 30,
	2025		2024
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	17,212	$	46,827
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	79,133		105,987
Bargain purchase gain	—		(19,898)
Amortization of deferred financing costs	809		—
Deferred tax benefit	(19,569)		(7,762)
Unrealized foreign exchange gain	(347)		(613)
Stock-based compensation expense	4,683		3,208

Derivative instruments loss, net	767		209
Cash settlements paid on matured derivative contracts, net	(141)		(15)


Credit losses and other	485		5,304


Equipment and other expensed in operations	3,937		1,589
Change in operating assets and liabilities:
Trade receivables, net	(23,772)		(39,456)
Accounts with joint venture owners, net	(4,292)		(4,739)
Egypt receivables and other, net	32,159		(394)
Crude oil inventory	483		12,153
Prepayments and other	(7,258)		(1,847)
Value added tax and other receivables	5,643		(5,713)
Other long-term assets	—		1,808
Accounts payable	7,120		(9,034)
Foreign income taxes payable	(18,328)		24,327

Accrued liabilities and other	(11,230)		(42,756)
Net cash provided by operating activities	67,494		69,185
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures	(152,728)		(61,530)
Cash acquired in business combination, net of cash paid	—		412
Acquisition of oil and gas properties	(3,034)		—
Net cash used in investing activities	(155,762)		(61,118)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock	—		447
Proceeds from borrowings	60,000		—
Dividend distribution	(19,807)		(19,647)
Payments for treasury shares	(709)		(6,803)
Deferred financing costs paid	(7,100)		—
Payments of finance lease	(9,781)		(6,261)
Net cash provided by (used in) in financing activities	22,603		(32,264)
Effects of exchange rate changes on cash	53		(4)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(65,612)		(24,201)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD	97,726		129,178
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	32,114	$	104,977

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)


	Nine Months Ended September 30,
	2025		2024
	(in thousands)
Supplemental disclosure of cash flow information:
Income taxes paid in-kind with crude oil	$	32,263	$	—
Interest paid, net of amounts capitalized	$	5,043	$	4,900
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	1,260	$	8,894

Recognition of right-of-use finance lease assets and liabilities	$	2,372	$	—
Recognition of right-of-use operating lease assets and liabilities	$	—	$	2,035
Asset retirement obligation revisions	$	58	$	15,796

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, as well as 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, 2024, 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 using either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when the Company has determined that the balance will not be collected.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(in thousands)

Balance at beginning of period	$	(2,556)	$	(12,604)	$	(2,554)	$	(6,029)
Credit losses and other	(288)		(69)		(925)		(5,222)
Credit recoveries and other	(196)		—		439		—
Reversal of allowance resulting from the settlement of the related receivable	—		11,200		—		11,200
Foreign currency loss	—		(425)		—		(1,847)
Balance at end of period	$	(3,040)	$	(1,898)	$	(3,040)	$	(1,898)

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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 September 30, 2025 and December 31, 2024.


		As of September 30, 2025
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Assets
Derivative asset	Prepayments and other	$	—	$	89	$	—	$	89

		$	—	$	89	$	—	$	89
Liabilities
Derivative liability	Accrued liabilities and other	$	—	$	613	$	—	$	613
		$	—	$	613	$	—	$	613


		As of December 31, 2024
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Assets
Derivative asset	Prepayments and other	$	—	$	119	$	—	$	119
Derivative asset, noncurrent	Other long term assets	$	—	$	1,209	$	—	$	1,209
		$	—	$	1,328	$	—	$	1,328
Liabilities
Derivative liability	Accrued liabilities and other	$	—	$	17	$	—	$	17
		$	—	$	17	$	—	$	17

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 not limited to, the contractual price of the underlying position, current market prices, crude oil forward curves, discount rates, and volatility factors.

2. NEW ACCOUNTING STANDARDS

Not Yet Adopted

In December 2023, the Financial Accounting Standards Board (“FASB”) issued new guidance to improve income tax disclosures to provide information to assess how an entity’s operations and related tax risks and tax planning and operational opportunities affect its tax rate and prospects for future cash flows. The rules became effective for annual periods beginning after December 15, 2024. The standard modifies required income tax disclosures. This ASU is not expected to have a material impact on our consolidated financial statements other than increased disclosure requirements.

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 to our 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

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adoption is permitted. The Company is currently evaluating the impact of adopting this ASU to our notes to the consolidated financial statements and processes.

3. ACQUISITIONS

Acquisition of Interest in CI-705 Block

In March 2025, the Company farmed into the CI-705 block offshore Côte d’Ivoire. The Company is the operator of the CI-705 block with a 70% working interest and a 100% paying interest through a commercial carry arrangement and is partnering with two other parties. The CI-705 block is located in the Tano basin, west of the Company's CI-40 Block, where the Baobab and Kossipo oil fields are located. The total amount of acquisition costs for this transaction is approximately $3.0 million.

FPSO Acquisition

In February 2025, the Company, through the joint operating agreement operator, completed the acquisition of the Baobab floating, production, storage and offloading vessel (the “Baobab FPSO”) in Côte d'Ivoire for a total purchase price of $20.0 million, or approximately $5.5 million net cost to the Company.

Svenska Acquisition

On April 30, 2024, the Company completed the acquisition of all of the issued shares in the capital of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden (the “Svenska Acquisition”). The total purchase price consideration was $40.2 million and was funded with Vaalco’s cash-on-hand. Cash acquired in the business combination included $31.8 million of cash and cash equivalents as well as restricted cash of $8.8 million which nets to $0.4 million cash received on the business combination within the purchase price allocation.

As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, an initial $19.9 million bargain purchase gain was recognized as of the close date. The purchase price allocation was finalized in the fourth quarter of 2024 and the Company made adjustments to the amounts assigned to the net assets acquired based on new information obtained about facts and circumstances that existed as of the Svenska Acquisition date. As a result, the bargain purchase gain was reduced by $6.4 million. The bargain purchase gain is primarily attributable to a stronger forward pricing curve for oil and gas reserves on the date of the closing of the acquisition than was used for the purposes of the negotiations of the purchase price paid for Svenska. The Svenska Acquisition qualified as a business combination and was accounted for using the acquisition method of accounting.

4. SEGMENT INFORMATION

The Company’s operations are based in Gabon, Egypt, Côte d'Ivoire, Canada, Nigeria and Equatorial Guinea. 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 are 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 nine months ended September 30, 2025 and 2024, as well as long-lived assets and segment assets at September 30, 2025 and December 31, 2024 are as follows:

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	Three Months Ended September 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	$	21,271	$	35,696	$	4,040	$	—	$	—	$	—	$	61,007
Operating costs and expenses:
Production expense	12,092		13,767		1,922		587		1,504		—		29,872
Exploration expense	167		—		—		—		186		—		353
Depreciation, depletion and amortization	7,145		9,308		2,832		—		861		409		20,555
General and administrative expense	779		296		46		63		572		7,089		8,845
Credit losses and other	196		—		—		288		—		—		484
Total operating costs and expenses	20,379		23,371		4,800		938		3,123		7,498		60,109

Operating income (loss)	892		12,325		(760)		(938)		(3,123)		(7,498)		898
Other income (expense):
Derivative instruments loss, net	—		—		—		—		—		(1,093)		(1,093)
Interest expense, net	(809)		(184)		—		—		(1,085)		(255)		(2,333)

Other income (expense), net	(154)		80		(60)		3		242		(78)		33
Total other income (expense), net	(963)		(104)		(60)		3		(843)		(1,426)		(3,393)
Income (loss) before income taxes	(71)		12,221		(820)		(935)		(3,966)		(8,924)		(2,495)
Income tax (benefit) expense	(3,902)		5,671		—		—		(5,077)		(288)		(3,596)
Net income (loss)	3,831		6,550		(820)		(935)		1,111		(8,636)		1,101
Consolidated capital expenditures	$	14,074	$	7,113	$	490	$	(61)	$	33,484	$	309	$	55,409


	Nine Months Ended September 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	$	132,026	$	102,873	$	14,935	$	—	$	18,396	$	—	$	268,230
Operating costs and expenses:
Production expense	59,746		38,898		6,533		1,274		8,618		1		115,070
Exploration expense	167		—		—		—		2,706		—		2,873
Depreciation, depletion and amortization	33,239		26,579		9,382		—		9,249		684		79,133
General and administrative expense	1,224		399		77		212		1,435		23,046		26,393
Credit (recovery) losses and other	(440)		—		—		925		—		—		485
Total operating costs and expenses	93,936		65,876		15,992		2,411		22,008		23,731		223,954

Operating income (loss)	38,090		36,997		(1,057)		(2,411)		(3,612)		(23,731)		44,276
Other income (expense):
Derivative instruments loss, net	—		—		—		—		—		(767)		(767)
Interest expense, net	(2,680)		(608)		—		—		(2,373)		(538)		(6,199)

Other income (expense), net	(917)		141		338		(2)		181		(369)		(628)
Total other income (expense), net	(3,597)		(467)		338		(2)		(2,192)		(1,674)		(7,594)
Income (loss) before income taxes	34,493		36,530		(719)		(2,413)		(5,804)		(25,405)		36,682
Income tax (benefit) expense	10,341		14,201		—		—		(15,312)		10,240		19,470
Net income (loss)	$	24,152	$	22,329	$	(719)	$	(2,413)	$	9,508	$	(35,645)	$	17,212
Consolidated capital expenditures	$	30,379	$	20,954	$	2,006	$	499	$	93,425	$	326	$	147,589

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	Three Months Ended September 30, 2024
(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Cote d'Ivoire		Corporate and Other		Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	47,608	$	34,544	$	8,387	$	—	$	49,795	$	—	$	140,334
Operating costs and expenses:
Production expense	13,932		12,477		3,015		195		12,701		4		42,324
Exploration expense	—		—		—		—		—		—		—
Depreciation, depletion and amortization	12,796		8,729		6,106		—		19,184		216		47,031
General and administrative expense	241		(79)		(4)		62		1,061		5,648		6,929
Credit losses and other	—		—		—		69		—		—		69
Total operating costs and expenses	26,969		21,127		9,117		326		32,946		5,868		96,353
Other operating income, net	—		—		102		—		—		—		102
Operating income (loss)	20,639		13,417		(628)		(326)		16,849		(5,868)		44,083
Other income (expense):
Derivative instruments gain (loss), net	—		—		—		—		(169)		379		210
Interest (expense) income, net	(964)		(360)		—		—		2,029		(1,293)		(588)
Bargain Purchase Gain	—		—		—		—		—		—		—
Other income (expense), net	(72)		(101)		669		(4)		(37)		(597)		(141)
Total other income (expense), net	(1,036)		(461)		670		(4)		1,823		(1,511)		(519)
Income (loss) before income taxes	19,603		12,956		42		(330)		18,672		(7,379)		43,564
Income tax expense	12,932		3,613		—		—		8,454		7,575		32,574
Net income (loss)	$	6,671	$	9,343	$	42	$	(330)	$	10,218	$	(14,953)	$	10,990
Consolidated capital expenditures	$	8,859	$	1,698	$	3,014	$	38	$	11,158	$	1,839	26,606


	Nine Months Ended September 30, 2024
(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Côte d'Ivoire		Corporate and Other		Total
Revenues:
Crude oil, natural gas and natural gas liquids sales	$	158,786	$	106,986	$	24,460	$	—	$	67,035	$	—	$	357,267
Operating costs and expenses:
Production expense	49,131		38,652		8,753		712		29,606		5		126,859
Exploration expense	—		48		—		—		—		—		48
Depreciation, depletion and amortization	39,591		25,481		15,297		—		25,233		385		105,987
General and administrative expense	1,194		297		(119)		233		1,185		18,440		21,230
Credit losses and other	20		4,812		—		390		—		—		5,222
Total operating costs and expenses	89,936		69,290		23,931		1,335		56,024		18,830		259,346
Other operating income (expense), net	(34)		—		102		—		—		—		68
Operating income (loss)	68,816		37,696		631		(1,335)		11,011		(18,830)		97,989
Other income (expense):
Derivative instruments loss, net	—		—		—		—		(169)		(211)		(380)
Interest (expense) income, net	(3,439)		(1,120)		38		—		489		1,392		(2,640)
Bargain purchase gain	—		—		—		—		—		19,898		19,898
Other income (expense), net	(303)		(101)		674		(2)		(338)		(3,856)		(3,925)
Total other income (expense), net	(3,742)		(1,221)		713		(2)		(18)		17,223		12,953
Income (loss) before income taxes	65,074		36,475		1,344		(1,337)		10,993		(1,608)		110,942
Income tax expense	38,956		19,395		—		—		5,404		360		64,115
Net income (loss)	$	26,118	$	17,080	$	1,344	$	(1,337)	$	5,589	$	(1,967)	$	46,827
Consolidated capital expenditures	$	20,248	$	7,894	$	22,728	$	38	$	18,310	$	3,840	$	73,058

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(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Côte d'Ivoire		Corporate and Other		Total
Long-lived assets:
As of September 30, 2025	$	158,534	$	143,504	$	101,256	$	11,140	$	204,546	$	4,756	$	623,736
As of December 31, 2024	$	153,576	$	149,129	$	104,891	$	10,641	$	114,756	$	5,110	$	538,103


(in thousands)	Gabon		Egypt		Canada		Equatorial Guinea		Côte d'Ivoire		Corporate and Other		Total
Total assets:
As of September 30, 2025	$	290,380	$	258,128	$	105,756	$	13,547	$	237,578	$	45,044	$	950,433
As of December 31, 2024	$	300,568	$	269,905	$	113,310	$	12,331	$	187,264	$	71,572	$	954,950

5. EARNINGS PER SHARE

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(in thousands)
Net income (numerator):
Net income	$	1,101	$	10,990	$	17,212	$	46,827
Income attributable to unvested shares	7		(145)		(319)		(491)
Numerator for basic	1,108		10,845		16,893		46,336
Loss attributable to unvested shares	—		—		—		—
Numerator for dilutive	$	1,108	$	10,845	$	16,893	$	46,336

Weighted average shares (denominator):
Basic weighted average shares outstanding	104,258		103,743		103,986		103,644
Effect of dilutive securities	25		99		24		84
Diluted weighted average shares outstanding	104,283		103,842		104,010		103,728
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be antidilutive	1,030		734		1,049		437

6. 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

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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 are 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 September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues from customer contracts:	(in thousands)
Sales under the COSPA or COSMA(1)	$	24,287	$	54,933	$	121,722	$	182,048
Gabonese government share of Profit Oil taken in-kind	—		—		30,394		—
Carried interest recoupment	495		652		561		1,826
Royalties	(3,511)		(7,977)		(20,651)		(25,088)
Net revenues	$	21,271	$	47,608	$	132,026	$	158,786

(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 September 30, 2025 and December 31, 2024, the Company had $23.4 million and $40.0 million, of foreign income tax payable, respectively.

Egypt

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues from customer contracts:	(in thousands)
Gross sales	$	58,271	$	63,432	$	171,115	$	191,938
Royalties	(22,392)		(28,714)		(67,731)		(84,550)
Selling costs	(183)		(174)		(511)		(402)
Net revenues	$	35,696	$	34,544	$	102,873	$	106,986

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Canada

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues from customer contracts:	(in thousands)
Oil revenue	$	3,278	$	8,039	$	12,354	$	21,739
Gas revenue	196		224		1,404		1,429
NGL revenue	1,386		1,984		4,405		5,835
Other revenue	32		24		119		70
Royalties	(666)		(1,533)		(2,688)		(3,801)
Selling costs	(186)		(351)		(659)		(812)
Net revenues	$	4,040	$	8,387	$	14,935	$	24,460

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 Cote d'Ivoire from contracts with customers:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues from customer contracts:	(in thousands)
Sales under the sales and purchase agreements	$	—	$	49,795	$	16,527	$	67,035
Cote d'Ivoire government share of Profit Oil taken in-kind	—		—		1,869		—
Net revenues	$	—	$	49,795	$	18,396	$	67,035

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. As of September 30, 2025 and December 31, 2024, the Company had $0.4 million and $1.7 million of foreign income tax payable, respectively.

Information about the Company’s most significant customers

For the three and nine months ended September 30, 2025 and 2024, our revenue concentration by major customers are shown on the table below.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2025	2024	2025	2024
Gabon	100%	100%	100%	100%
Egypt	100%	100%	100%	100%
Côte d'Ivoire	—%	100%	100%	100%
Canada	49%, 18% and 18%	59%, 22% and 16%	53%, 20% and 15%	44%, 30% and 21%

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7. 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 September 30, 2025		As of December 31, 2024
	(in thousands)
Crude oil, natural gas and NGLs properties and equipment, net
Wells, platforms and other production facilities	$	1,627,851	$	1,593,243
Work-in-progress	143,598		44,517
Unproved properties	66,954		60,761
Capitalized equipment, spare parts and other	92,850		75,581
	1,931,253		1,774,102
Accumulated depreciation, depletion, amortization and impairment	(1,307,517)		(1,235,999)
Crude oil, natural gas and NGLs properties and equipment, net	$	623,736	$	538,103

8. 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 September 30, 2025:


		Settlement Period
Instrument	Index	October 2025 to December 2025		January 2026 to March 2026		April 2026 to June 2026		July 2026 to September 2026
Crude oil:




Collars	Dated Brent
Total volumes (Bbls)		480,000		400,000		360,000		75,000
Weighted average floor price ($/Bbl)		$	60.83	$	62.29	$	61.88	$	65.00
Weighted average ceiling price ($/Bbl)		$	67.81	$	68.63	$	67.95	$	71.00

Natural Gas:
Swaps	AECO 7A
Total volumes (GJs)(a)		214,000		150,000		—		—
Weighted average fixed price (CAD/GJ)		$	2.48	$	2.86	$	—	$	—

(a) One gigajoule (GJ) equals one billion joules (J). A gigajoule of natural gas is approximately 25.5 cubic meters standard conditions.

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 September 30,				Nine Months Ended September 30,
Derivative Item	Statements of Operations Line	2025		2024		2025		2024
		(in thousands)				(in thousands)
Commodity derivatives	Cash settlements received (paid) on matured derivative contracts, net	$	(355)	$	18	$	(141)	$	(15)
	Unrealized gain (loss)	(738)		192		(626)		(365)
	Derivative instruments gain (loss), net	$	(1,093)	$	210	$	(767)	$	(380)

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9. CURRENT ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:


	As of September 30, 2025		As of December 31, 2024
	(in thousands)
Accrued accounts payable invoices	$	39,395	$	48,913
State oil liability	18,244		19,616
Accrued capital expenditures	17,759		8,923

Egypt modernization payable	9,742		9,933
Gabon contractual obligations	8,193		6,977
Accrued wages and other compensation	6,014		4,956
Seismic data	2,485		2,455
Asset retirement obligation, current portion	92		1,174
Other	5,393		4,763
Total accrued liabilities and other	$	107,317	$	107,710

10. COMMITMENTS AND CONTINGENCIES

Abandonment funding

Under the terms of the Etame PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. At September 30, 2025, $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.

Share Buyback Program

On November 1, 2022, the Company announced that the Company’s board of directors formally ratified and approved a share buyback program. The board of directors also directed management to implement a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The 10b5-1 Plan provided for an aggregate purchase of currently outstanding common stock up to $30 million over a maximum period of 20 months. Payment for shares repurchased under the share buyback program were funded using the Company's cash on hand and cash flow from operations. The share buyback program was completed on March 12, 2024. Under the share buyback program, we purchased a total of 6,797,711 shares at an average price of $4.41 per share.

Merged Concession Agreement

The Company is a party to the Merged Concession Agreement with the Egyptian General Petroleum Corporation (“EGPC”). In accordance with the Merged Concession Agreement, the Company is required to make a $10.0 million annual modernization payment to EGPC each year through February 1, 2026. The $10.0 million modernization payment due February 1, 2025 was fully offset against receivables owed to the Company from EGPC. On the unaudited condensed consolidated balance sheet as of September 30, 2025, the remaining modernization payment liability of $9.7 million was recorded in the line item “Accrued liabilities and other.”

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 September 30, 2025, 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.

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In addition, as of February 1, 2020 (the “Merged Concession Effective Date”), an effective date adjustment was owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date (the “Effective Date Adjustment”). The Company recognized a receivable in connection with the Effective Date Adjustment of $67.5 million as of October 2022, based on historical realized prices (the “Backdated Receivable”). The Backdated Receivable was fully settled as of March 31, 2025.

Drilling Rig Commitment

The Company entered into a bareboat charter agreement (the “Bareboat Charter”) during the fourth quarter of 2024 to charter a drilling rig for its drilling program in Gabon that is expected to commence during the fourth quarter of 2025. 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 is expected to commence once the mobilization of the drilling rig towards the Company’s first well has commenced and has a noncancellable period of 300 days plus five single well options. The Bareboat Charter stipulates fixed day rates and other variable payments.

11. DEBT

In April 2025, the Company drew down $60.0 million under the 2025 RBL Facility. The borrowing accrues interest at a rate of 10.8% per annum which is based on the Term SOFR plus the applicable margin of 6.5% per annum. In addition, the borrowing is due to be repaid within three months from the drawdown date with, subject to certain conditions, the option to rollover the debt upon maturity.

As of September 30, 2025, there were $60.0 million of outstanding borrowings under the 2025 RBL Facility. There were no outstanding borrowings as of December 31, 2024.

In addition, as of September 30, 2025 and December 31, 2024, we were in compliance with all of our debt covenants.

2025 RBL Facility

On March 4, 2025, the Company and certain of its subsidiaries (the “Vaalco Energy Group”), entered into a reserves-based facility agreement (the “2025 Facility Agreement”) providing for a senior secured reserve-based revolving credit facility (the “2025 RBL Facility”) with The Standard Bank of South Africa Limited (acting through its Corporate and Investment Banking Division) as agent and security agent, The Standard Bank of South Africa Limited, Isle of Man Branch and the other financial institutions named in the 2025 Facility Agreement (the “Lenders”), providing for the 2025 RBL Facility.

The 2025 RBL Facility had initial aggregate commitments of $190.0 million (the “Initial Total Commitments”) as of March 4, 2025, with an initial borrowing base of $182.0 million. In accordance with the conditions that were met subsequent to entering into the 2025 Facility Agreement, the initial borrowing base was increased to $184.0 million in April 2025. The Initial Total Commitments originally would reduce semi-annually by $19.0 million starting from September 30, 2026. 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. The Company may, at any time prior to the date falling 30 months from the date of the 2025 Facility Agreement and subject to the conditions and process set out in the 2025 Facility Agreement, give notice to the agent to increase the Initial Total Commitment up to a maximum amount of $300.0 million. On June 30, 2025, the initial borrowing base redetermination was completed pursuant to the terms of the RBL Facility Agreement, which resulted in an increase to the borrowing base from $184.0 million to $186.6 million. As of September 30, 2025, we had $190.0 million of aggregate facility commitments and $126.6 million of available borrowing capacity under the 2025 RBL Facility.

Effective October 17, 2025, the Lenders unanimously approved an increase in the Company’s borrowing base under the 2025 RBL Facility from $186.6 million to $190.0 million after the Company completed its semi-annual borrowing base redetermination process. In addition, the Lenders approved to (i) extend the first date on which the Initial Total Commitments will be reduced from September 30, 2026 to March 31, 2027, and (ii) update the semi-annual commitment reduction amounts from $19.0 million to $10.0 million on March 31, 2027, and $22.5 million starting on September 30, 2027.

In addition, on November 7, 2025, subject to certain conditions precedent, certain existing Lenders under the 2025 RBL Facility agreed to increase their initial commitment effective January 23, 2026 (the “Effective Increase Date”) so that the aggregate borrowing base under the 2025 RBL Facility as of the Effective Increase Date would increase from

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$190.0 million to $240.0 million. The increase in commitments was undertaken with the existing accordion feature included in 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 tanker facility named Baobab Ivorian MV10 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.

The 2025 RBL Facility 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 over the shares in 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 trailing 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 Vaalco Energy Group 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, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the then-total commitments exceeds the higher of the total outstanding amount of loans and the borrowing base amount. The Company is also required to pay customary technical and modelling 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 threshold 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 exceeds 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 acquisitions 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 contains 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

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Agreement and any outstanding unfunded commitments may be terminated. In addition, if any principal amount payable is not paid upon 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.

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.

12. 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 September 30, 2025 and 2024.

The Company’s effective tax rate for the three months ended September 30, 2025, and 2024, excluding the impact of discrete items, was (81.21)% and 64.85%, respectively. The Company’s effective tax rate for the nine months ended September 30, 2025 and 2024, excluding the impact of discrete items, was 59.48% and 59.10%, respectively. For the three and nine months ended September 30, 2025 and 2024, the Company’s overall effective tax rate was primarily impacted by tax rates in foreign jurisdictions higher than the US statutory rate and by non-deductible items associated with operations.

For the three months ended September 30, 2025, the income tax benefit of $3.6 million includes a $3.9 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 $0.3 million for the period. For the nine months ended September 30, 2025, the income tax expense of $19.5 million includes a $6.4 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, income taxes were $25.9 million for the period.

As of September 30, 2025, 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.

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 are not material and the Company is still assessing the impact of provisions that are not yet effective.

13. RELATED PARTY TRANSACTIONS

The Company has entered into various agreements with related parties. The Company paid approximately $0.1 million and $0.2 million to these related parties for the three and nine months ended September 30, 2025, respectively. The amounts were primarily for contract engineering services paid to an entity owned and controlled by a related party of an officer of the Company.

14. 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 our Canadian segment to USD.

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The components of accumulated other comprehensive income are as follows:


	Currency Translation Adjustments
	(in thousands)
Balance at December 31, 2024	$	(4,962)
Amounts reclassified from accumulated other comprehensive income (loss)	117
Balance at March 31, 2025	(4,845)
Amounts reclassified from accumulated other comprehensive income (loss)	4,759
Balance at June 30, 2025	(86)
Amounts reclassified from accumulated other comprehensive income (loss)	(1,799)
Balance at September 30, 2025	$	(1,885)

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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 (collectively, “OPEC+”) 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;

•our ability to remediate our material weaknesses;

•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, will be sufficient to support our operations and cash requirements;

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

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

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

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

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

•the impact of competition;

•our ability to identify and complete complementary opportunistic acquisitions;

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

•weather conditions;

•the uncertainty of estimates of crude oil, natural gas and NGLs reserves;

•currency exchange rates and regulations;

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

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

•the impact and duration of scheduled maintenance of the floating, production, storage and offloading (“FPSO”) vessel in Côte d'Ivoire;

•the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon that was conducted by the government of Gabon;

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

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

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

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

•general economic conditions, including any future economic downturn, the impact of inflation, and disruption in financial credit and other disruptions resulting from geo-political events such as the Russian invasion of Ukraine, conflicts in the Middle East, and trade tensions between the U.S. and China;

•our ability to enter into new customer contracts;

•changes in customer demand and producers’ supply;

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

•actions by our joint venture owners;

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

•the outcome of any governmental audit;

•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, 2024 (“2024 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 2024 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 strong production and reserve portfolio of assets in Gabon, Egypt, Equatorial Guinea, Nigeria, Côte d'Ivoire, as well as Canada. We are currently engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.

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RECENT DEVELOPMENTS

Quarterly Cash Dividends

The Company paid a quarterly cash dividend of $0.0625 per share of common stock for the third quarter of 2025 ($0.25 annualized) on September 19, 2025 to stockholders of record at the close of business on August 22, 2025. The Company also announced its next quarterly cash dividend of $0.0625 per share of common stock for the fourth quarter of 2025 ($0.25 annualized) to be paid on December 24, 2025 to stockholders of record at close of business on November 21, 2025. 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.

Recent Operational Updates

Gabon

The Company secured a drilling rig in December 2024 in conjunction with its 2025/2026 drilling program, which is expected to begin during the fourth quarter of 2025, once the drilling rig completes its current commitments. The program includes drilling multiple development wells, and appraisal or exploration wells, and perform workovers, with options to drill additional wells. We plan to drill wells at both the Etame platform and at its Seent platform, as well as a re-drill and a number of workovers in the Ebouri field to access production and reserves that were previously removed from proved reserves due to the presence of hydrogen sulfide.

In July 2025, the Company performed planned, staged shutdowns of the Gabon platforms to perform safety inspections and necessary maintenance to increase the integrity and reliability of the assets. This is the first full field maintenance shutdown that the Company has performed since the new Floating Storage and Offloading vessel (“FSO”) was brought online in 2022. All fields were successfully brought back online and the planned turnaround was completed on budget and with no safety or environmental incidents.

Egypt

The current drilling campaign in Egypt began in December 2024 and has continued through the third quarter of 2025. During the third quarter of 2025, four development wells were drilled in the Eastern Desert, of which three were completed during the same period and the fourth well was completed in October 2025. Also, during the third quarter of 2025, we drilled one exploration well in the Western Desert which was completed in October 2025. Additionally, continuous well interventions, workovers and optimization activities were carried out throughout the third quarter of 2025 to enhance production levels.

Canada

In 2025, the Company decided to defer the drilling of additional wells in Canada based on a reassessment of capital allocation priorities across the portfolio and to ensure that investment is directed toward projects with the highest expected returns. Therefore, the Canadian division is looking towards lower-cost optimization projects to enhance productivity by year-end.

Côte d'Ivoire

As part of the planned dry dock refurbishment, the Baobab FPSO ceased hydrocarbon production on January 31, 2025 and the final lifting of crude oil from the FPSO took place in February 2025. The vessel departed from the field in late March 2025 and arrived at the shipyard in Dubai ahead of schedule in mid-May 2025. The FPSO refurbishment is progressing well and has now been underway for the last five months in the shipyard. A rig has been secured for significant development drilling which is expected to begin in 2026 after the FPSO returns to service, bringing meaningful additions to production from the main Baobab field in CI-40. The Company is also evaluating the anticipated impact of the potential future development of the Kossipo field, which is also on the CI-40 license.

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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.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the nine months ended September 30, 2025 and 2024 are as follows:


	Nine Months Ended September 30,
	2025		2024		Change in 2025 over 2024
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	86,969	$	134,521	$	(47,552)
Net change in operating assets and liabilities	(19,475)		(65,336)		45,861
Net cash provided by operating activities	67,494		69,185		$	(1,691)

Net cash used in investing activities	(155,762)		(61,118)		(94,644)

Net cash provided by (used in) financing activities	22,603		(32,264)		54,867
Effects of exchange rate changes on cash	53		(4)		57
Net change in cash, cash equivalents and restricted cash	$	(65,612)	$	(24,201)	$	(41,411)

The $1.7 million decrease in net cash provided by operating activities during the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 was driven primarily by changes in operating assets and liabilities during the period. The net increase in changes provided by operating assets and liabilities of $45.9 million for the nine months ended September 30, 2025 compared to the same period of 2024 was primarily related to the overall decrease in accrued liabilities and accounts payable, decrease in trade receivables due to the settlement of the Egypt backdated receivables and improvement of trade receivables, value added tax and other receivables. The favorable changes in the cash flows from operating activities are offset primarily by a decrease in foreign taxes payable.

The $94.6 million change in net cash used in investing activities during the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024, 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. For the nine months ended September 30, 2024, cash used in investing activities was due to capital spending costs associated with the development drilling programs in Egypt and Canada not exceeding prior year expenditures along with reduced current year expenditures for Gabon. In addition, Vaalco used $40.2 million in cash for the acquisition of Svenska which is offset by the cash received from Svenska in the amount of $40.6 million.

Net cash provided by financing activities during the nine months ended September 30, 2025 primarily consists of $60.0 million in proceeds from borrowings under the 2025 RBL Facility, offset by cash used of $19.8 million for dividend distributions, $7.1 million of payments for deferred financing costs and $9.8 million of principal payments on our finance leases. For the nine months ended September 30, 2024, cash used in financing activities included $19.6 million for dividend distributions, $6.8 million for treasury stock repurchases made under our stock repurchase plan or as a result of tax withholding on options exercised and on vested restricted stock, and $6.3 million of principal payments on our finance leases partially offset by $0.4 in proceeds from options exercised.

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Capital Expenditures

For the nine months ended September 30, 2025, we had accrual basis capital expenditures of $147.6 million compared to $73.1 million accrual basis capital expenditures for the same period in 2024. For the nine months ended September 30, 2025, our cash spending primarily related to the new wells drilled as part of the drilling campaign in Egypt as well as expenditures associated with the refurbishment of the FPSO in Côte d'Ivoire. During the same period in 2024, our cash spending primarily related to the Svenska acquisition as well as payments for the 2024 drilling campaigns in both Egypt and Canada.

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

Commodity Price Hedging

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

Due to the inherent volatility in crude oil prices, we use commodity derivative instruments such as swaps, costless collars and put options to hedge price risk associated with a portion of our anticipated crude oil and gas production. These instruments allow us to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. The instruments provide only partial protection against declines in crude oil and gas prices and may limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. We do not speculate on commodity prices, but rather attempt to hedge physical production by individual hydrocarbon product in order to protect returns. The counterparty to our derivative swap transactions was a major oil company’s trading subsidiary, and our costless collars are with Glencore. We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in the unaudited condensed consolidated statements of operations and other comprehensive income. We record such derivative instruments as assets or liabilities in the unaudited condensed consolidated balance sheets. 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 8. Derivatives to the unaudited condensed consolidated financial statements for further discussion.

Cash on Hand

At September 30, 2025, we had unrestricted cash of $24.0 million. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations and capital expenditures.

Capital Resources, Liquidity and Cash Requirements

Our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities. 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 FPSO refurbishment, 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 for other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and

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

Merged Concession Agreement

For information on the Merged Concession Agreement, see Part I, Item 1, Note 10. Commitments and Contingencies to the unaudited condensed consolidated financial statements.

2025 Facility Agreement and Available Credit

For information on our 2025 Facility Agreement and available credit, see Part I, Item 1., Note 11. Debt, to the unaudited condensed consolidated financial statements.

Cash Requirements

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

Abandonment Funding - Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the 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 September 30, 2025, 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.

Capital Projects - In December 2024, Vaalco secured a rig for the 2025/26 drilling campaign at Etame and is currently finalizing locations and planning for the next drilling campaign, which is expected to begin during the fourth quarter of 2025. In Egypt, additional drilling and completion activities are expected to continue during the last quarter of 2025.

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 of Canada and Egypt. The annual costs of these leases are significant to us.

Merged Concession Agreement - On January 20, 2022, the Merged Concession Agreement was executed with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. As part of the agreement, the Company is required to make an annual modernization payment of $10.0 million per year to EGPC through February 2026. In accordance with the Merged Concession Agreement, we agreed to substitute the 2023, 2024 and 2025 payments and issue three $10.0 million credits against receivables owed from EGPC. We will make one further annual modernization payment of $10.0 million on February 1, 2026. For information on the Merged Concession Agreement, see Part I, Item 1, Note 10. Commitments and Contingencies to the unaudited condensed consolidated financial statements.

Financial Work Commitments - In Egypt, we also have financial work commitments of $50.0 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 September 30, 2025, our financial work commitments have exceeded the five-year minimum $50 million threshold and any excess carries forward to offset against subsequent five-year commitments.

FPSO Maintenance – The Baobab FPSO arrived at the shipyard in Dubai ahead of schedule in mid-May for planned maintenance and upgrades. The FPSO refurbishment is now underway in the shipyard. The FPSO is expected to return to service in 2026.

Drilling Rig Commitment - The Company entered into a bareboat charter agreement (the “Bareboat Charter”) during the fourth quarter of 2024 to charter a drilling rig for its drilling program in Gabon that is expected to commence during the fourth quarter of 2025. 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 is expected to commence once the mobilization of the drilling rig towards the Company’s first well has commenced and has a

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noncancellable period of 300 days plus five single well options. The Bareboat Charter stipulates fixed day rates and other variable payments.

Trends and Uncertainties

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. On October 9, 2025, Israel, Hamas, the United States and other countries in the region agreed to a framework for a ceasefire in Gaza between Israel and Hamas, which if sustained, could reduce regional instability in the Eastern Mediterranean, and improve security conditions affecting Egypt operations and related energy supply chains. However, whether the ceasefire will be sustained or will result in a lasting de-escalation of tensions in the region is unknown. Additionally, geopolitical tensions and localized disruptions persist in parts of West Africa, where we hold significant producing and development interests, require ongoing vigilance regarding political, economic, and security risks.

Additionally, global market forces including inflation, supply chain constraints due to lingering impacts from conflicts such as the Russia-Ukraine war, and shifts in U.S. trade policy including tariffs on energy-related goods, continue to increase costs and extend lead times for equipment and materials essential to drilling and production activities. These factors could affect project timing, cost structures, and overall operational efficiency. The Company also notes ongoing volatility in commodity prices driven by dynamic supply and demand fundamentals, energy transition policies, and broader macroeconomic uncertainties. Vaalco actively manages exposure to these risks through operational flexibility, diversified sourcing, and prudent financial planning to safeguard long-term growth and value creation.

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. While there is significant uncertainty as to the duration of these and any further tariffs, and the impacts these tariffs and any corresponding retaliatory tariffs will have on the oil and gas industry and on commodity prices, these tariffs, along with anticipated retaliatory measures from affected trading partners, have introduced new volatility into the global supply chain for energy infrastructure. While we do not maintain U.S. based production assets, our operations in Canada and 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.

Additionally, the evolving global trade environment may increase compliance complexity and affect the cost efficiency of international operations. Enhanced documentation requirements and new rules of origin associated with U.S. trade actions could impact our ability to efficiently move materials through international logistics hubs, such as those in Houston, Texas and could necessitate additional internal resources to maintain compliance. These complexities necessitate additional internal resources to ensure sustained compliance and efficient material flow.

The broader geopolitical trade environment, including retaliatory tariffs and ongoing trade tensions with key partners, continues to inject volatility into the global supply network, necessitating vigilant risk management and strategic sourcing to mitigate operational disruptions and cost impacts.

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. We are currently evaluating the provisions of the OBBBA law and the potential effects on our financial position, results of operations, and cash flows, however we do not anticipate any material financial impact from the passage of the OBBBA.

Moreover, to the extent U.S. policy shifts create uncertainty in bilateral relations or disrupt traditional trade partnerships, there could be indirect effects on our ability to manage risk and maintain favorable operating conditions in host countries. While we continue to monitor the evolving regulatory and trade landscape, we cannot predict the full impact of current or future tariffs, trade restrictions or retaliatory actions on our operations, financial condition or future capital deployment decisions.

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Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC. In addition, recent U.S. energy policy changes that prioritize domestic production and energy security, including through tax credits and development incentives, may influence global supply dynamics and capital flows, potentially altering the competitive landscape for international assets.

ESG and Climate Change Effects – Sustainability matters continue to attract public, political, regulatory and scientific attention.

While 2025 has seen a deceleration in the adoption of sustainability-oriented regulation, particularly in the U.S., and a noticeable shift by some financial institutions away from explicitly “ESG” or “Net Zero” branded initiatives due to perceived political or reputational sensitivities, we believe the underlying trend of focusing on sustainability remains consistent. Long-term structural pressures, including stakeholder expectations, evolving global market standards, and transition-related investment priorities, continue to support the integration of sustainability considerations into corporate strategy and capital markets.

The attention to climate change and environmental stewardship coupled with increasing government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, higher regulatory and compliance costs, additional governmental investigations and private litigation against the oil and gas industry, including Vaalco. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, voluntary efforts to reduce routine flaring, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on environmental, social and governance (“ESG”) matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries.

Climate-Related Disclosures – On March 27, 2025, the SEC ended its defense of the final rules on climate-related disclosures, effectively withdrawing its support for the regulation. The rules, which were adopted in March 2024, require publicly traded companies to disclose climate-related risks and greenhouse gas emissions. The SEC's decision to end its defense was made after a change in administration and a shift in policy, with Acting Chairman Mark Uyeda expressing concerns about the rule's costs and intrusiveness. While the rules remain on hold pending legal challenges, which, as of September 2025, have been held in abeyance by the Eighth Circuit Court of Appeals until such time as the SEC reconsiders the challenged rules by notice-and-comment rulemaking or renews its defense of the rules, the SEC's withdrawal of support signals a potential shift in direction for climate disclosure regulations. Despite this regulatory shift in the U.S., we remain committed to maintaining transparency and aligning with industry standards for similarly situated companies.

U.S. activity notwithstanding, for the past three years, the Company has refined its reporting in line with the recommendations of the Task Force on Climate-Related Disclosures (“TCFD”), which is recognized as the global standard in climate-related reporting and required by Vaalco to report against through its listing on the London Stock Exchange. The full TCFD report was included within the Company's 2024 Sustainability Report (rather than in the Annual Report on Form 10-K or in the annual report which was published in connection with the annual meeting), as the Sustainability Report details environmental, social and governance matters of which the TCFD report forms an important part. The 2024 Sustainability Report is available on the Company's website.

The Company considers itself aligned with both the TCFD's Governance and Strategy pillars and the recommendations therein. During 2025, the Company has made meaningful progress against certain of the underlying recommendations of the TCFD’s Governance and Strategy pillars and provides statements of intent to address these recommendations, including communicating its short-, mid- and long-range goals for emission reductions, beginning with its operated assets.

In June 2025, the UK government advanced its endorsement process for sustainability reporting standards by publishing exposure drafts for UK Sustainability Reporting Standards (“UK SRS”) S1 and S2, derived from the International Financial Reporting Standards (“IFRS”) S1 and S2 frameworks, and initiated a public consultation scheduled to conclude in autumn 2025. Pending final government approval and subsequent Financial Conduct Authority (FCA) rulemaking, UK listed businesses will be subject to phased implementation starting with climate-related disclosures, excluding Scope 3 greenhouse gas emissions in the first period, transitioning to full coverage in subsequent years. The UK approach eliminates fixed commencement dates and offers regulatory flexibility, with transitional reliefs supporting issuer compliance and a “climate-first” methodology for initial reports, ensuring a measured shift from existing TCFD

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requirements to the new UK SRS/IFRS-aligned disclosure regime. UK listed entities are advised to prepare for mandatory reporting in line with IFRS S1 and S2, anticipated from accounting periods beginning in 2026, subject to the outcomes of the consultation and final government direction.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

There have been no material changes to our critical accounting policies and estimates subsequent to December 31, 2024. For a discussion of the Company's critical accounting policies for the fiscal year ended December 31, 2024, please see our 2024 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 September 30, 2025 Compared to the Three Months Ended September 30, 2024

Net income for the three months ended September 30, 2025 was $1.1 million compared to a net income of $11.0 million during the same period of 2024. See discussion below for changes in revenues and expenses.

Crude oil, natural gas and NGLs revenues decreased $79.3 million, or approximately 57%, to $61.0 million during the three months ended September 30, 2025 from $140.3 million during the same period in 2024. The revenue decrease is primarily attributable to lower revenues in our Côte d'Ivoire and Canada segments.


	Three Months Ended September 30,				Increase/(Decrease)
	2025		2024
	(in thousands)



Net crude oil, natural gas, and NGLs revenue	$	61,007	$	140,334	$	(79,327)

Operating costs and expenses:
Production expense	29,872		42,324		(12,452)
Exploration expense	353		—		353
Depreciation, depletion and amortization	20,555		47,031		(26,476)
General and administrative expense	8,845		6,929		1,916
Credit losses and other	484		69		415
Total operating costs and expenses	60,109		96,353		(36,244)
Other operating income, net	—		102		(102)
Operating income	898		44,083		(43,185)
Other expense, net	(3,393)		(519)		(2,874)
Income before income taxes	(2,495)		43,564		(46,059)
Income tax expense	(3,596)		32,574		(36,170)
Net income	$	1,101	$	10,990	$	(9,889)

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The revenue changes in the three months ended September 30, 2025 compared to the same period in 2024 identified as related to changes in price or volume, are shown in the table below:


(in thousands)
Price	$	(16,704)
Volume	(62,369)
Other(1)	(254)
	(79,327)

(1) Other in the table above includes revenues attributed to carried interests.

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


	Three Months Ended September 30,
	2025		2024
Net crude oil, natural gas and NGLs production (MBoe)	1,417		2,004
Net crude oil, natural gas and NGLs sales (MBoe)	1,180		2,134

Average realized crude oil, natural gas and NGLs price ($/Boe)	$	51.26	$	65.41
Average Dated Brent spot price* ($/Bbl)	$	69.04	$	80.01

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

Crude oil, natural gas and NGL 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. The Company’s Gabon segment contributed $21.3 million of revenue to the Company’s total revenue during the three months ended September 30, 2025, a decrease of $26.3 million from the $47.6 million of revenue reported during the three months ended September 30, 2024. The decrease in revenues is primarily due to a sales volume decrease in Gabon from the 617 MBbls reported during the third quarter of 2024 to 333 MBbls for the three months ended September 30, 2025 combined with a lower average realized sales price received in Gabon of $62.40 per Bbl for three months ended September 30, 2025 compared to the $77.16 per Bbl average realized sales price received during the same period in 2024. The lower sales and production volumes is primarily a result of a planned and successful full field maintenance shutdown which occurred in July 2025. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 292 MBbls to 217 MBbls at September 30, 2025 and 2024, 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 September 30, 2025, the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contributed $35.7 million of revenue to the Company’s total revenue for the three months ended September 30, 2025, which is higher than the $34.5 million of revenue reported during the three months ended September 30, 2024. The increase in revenues was primarily due to an increase in sales volumes to 693 MBbls during the three months ended September 30, 2025 compared to 657 MBbls, during the three months ended September 30, 2024 partially offset by a decrease in average realized sales price from $52.58 per Bbl during the three months ended September 30, 2024 to $51.51 per Bbl during the same period in 2025.

Canada

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $4.0 million of revenue to the Company’s total revenue for the three months ended September 30, 2025, or a decrease of $4.4 million compared to $8.4 million of revenue reported during the three months ended September 30, 2024. The decrease in revenues was primarily due to lower average realized sales price received of $26.13 per Boe during the

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three months ended September 30, 2025 compared to the $36.95 per Boe received during the same period in 2024. Sales volumes in Canada decreased during the three months ended September 30, 2025 to 155 MBoe in comparison to 227 MBoe in the same period in 2024.

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 noted, the FPSO ceased production in January 2025 and its refurbishment is currently underway in the shipyard. The FPSO is expected to return to service in 2026. As such, there were no revenues from the Company's Côte d’Ivoire segment during the three months ended September 30, 2025. Revenues during the three months ended September 30, 2024 were $49.8 million with total sales volumes of 632 MBbls and an average sales price received of $78.75 per Bbl.

Production expenses decreased $12.5 million, or approximately 29%, for the three months ended September 30, 2025 to $29.9 million from $42.3 million for the same period in the prior year. The decrease was primarily driven by a reduction in production expenses in our Côte d’Ivoire segment. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended September 30, 2025 increased to $25.23 per barrel from $19.80 per barrel for the three months ended September 30, 2024.

Exploration expense for the three months ended September 30, 2025 of $0.4 million was attributable to the purchase of additional seismic data to be used in Block 705 in Cote d’Ivoire and to expenses related to Blocks G and H in Gabon. There were no exploration costs incurred during the same period in 2024.

Depreciation, depletion and amortization costs decreased by $26.5 million, or approximately 56%, for the three months ended September 30, 2025 to $20.6 million from $47.0 million during the same period in 2024. Since there was no production during the three months ended September 30, 2025 in Côte d’Ivoire, there was also no depletion expense recorded and therefore resulted in the decrease in the overall depletion expense for the period.

General and administrative expenses increased by $1.9 million, or 28%, for the three months ended September 30, 2025 to $8.8 million from $6.9 million during the same period in 2024. The increase in general and administrative expenses is primarily due to an increase in professional service fees and salaries and wages.

Credit losses and other increased by approximately $0.4 million for the three months ended September 30, 2025 compared to the same period in 2024. The increase in credit losses and other is primarily attributable to allowance charges related to the joint venture partners and value added tax receivables. Credit losses and other for the same period in 2024 was an insignificant amount due to a smaller joint venture partner receivable.

Derivative instruments gain (loss), net is attributable to our swaps and collars as discussed in Part I, Item 1, Note 8. Derivatives to the unaudited condensed consolidated financial statements. Derivative loss increased by $1.3 million to a loss of $1.1 million for the three months ended September 30, 2025 from a gain of $0.2 million during the same period in 2024. Derivative loss for the three months ended September 30, 2025 are 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 September 30, 2025. Our derivative instruments currently cover a portion of our production through September 2026 for oil and through December 2026 for natural gas.

Interest expense, net was $2.3 million for the three months ended September 30, 2025 compared to an expense of $0.6 million during the same period in 2024. The increase in net interest expense for the three months ended September 30, 2025 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 increased by $0.2 million to an income of less than $0.1 million for the three months ended September 30, 2025 from a $0.1 million expense during the same period in 2024. Other income (expense), net, normally consists primarily of foreign currency gains and losses.

Income tax expense (benefit) for the three months ended September 30, 2025 was a benefit of $3.6 million which includes a $3.9 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 $0.3 million for the period. Income tax expense for the three months ended September 30, 2024 was an expense of $32.6 million. This expense is comprised of current tax expense of $33.7 million including a $1.8 million favorable oil

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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 $35.5 million for the period.

Nine Months Ended September 30, 2025 Compared to the Nine Months Ended September 30, 2024

Net income for the nine months ended September 30, 2025 was $17.2 million compared to a net income of $46.8 million during the same period of 2024. See discussion below for changes in revenues and expenses.

Crude oil, natural gas and NGLs revenues decreased $89.0 million, or approximately 25%, to $268.2 million during the nine months ended September 30, 2025 from $357.3 million during the same period in 2024. The revenue decrease is primarily due to lower revenues in Gabon and Côte d’Ivoire.


	Nine Months Ended September 30,				Increase/(Decrease)
	2025		2024
	(in thousands)



Net crude oil, natural gas, and NGLs revenue	$	268,230	$	357,267	$	(89,037)

Operating costs and expenses:
Production expense	115,070		126,859		(11,789)
Exploration expense	2,873		48		2,825
Depreciation, depletion and amortization	79,133		105,987		(26,854)
General and administrative expense	26,393		21,230		5,163
Credit losses and other	485		5,222		(4,737)
Total operating costs and expenses	223,954		259,346		(35,392)
Other operating expense, net	—		68		(68)
Operating income	44,276		97,989		(53,713)
Other income (expense), net	(7,594)		12,953		(20,547)
Income before income taxes	36,682		110,942		(74,260)
Income tax expense	19,470		64,115		(44,645)
Net income	$	17,212	$	46,827	$	(29,615)

The revenue changes in the nine months ended September 30, 2025 compared to the same period in 2024 identified as related to changes in price or volume, are shown in the table below:


(in thousands)
Price	$	(39,969)
Volume	(47,917)
Other(1)	(1,151)
	$	(89,037)

(1) Other in the table above includes revenues attributed to carried interests.

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


	Nine Months Ended September 30,
	2025		2024
Net crude oil, natural gas and NGLs production (MBoe)	4,559		5,410
Net crude oil, natural gas and NGLs sales (MBoe)	4,662		5,388

Average realized crude oil, natural gas and NGLs price ($/Boe)	$	57.42	$	65.99
Average Dated Brent spot price* ($/Bbl)	$	71.01	$	82.50

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

Crude oil, natural gas and NGL 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. The Company’s Gabon segment contributed $132.0 million of revenue to the Company’s total revenue during the nine months ended September 30, 2025, a decrease of $26.8 million from the $158.8 million of revenue reported during the nine months ended September 30, 2024. The decrease in revenues is primarily due to the lower average realized sales price received in Gabon of $69.52 per Bbl for nine months ended September 30, 2025 compared to $81.55 per Bbl average realized sales price received during the same period in 2024. Additionally, there was a decrease in sales volume in Gabon to 1,891 MBbls for the nine months ended September 30, 2025 from the 1,947 MBbls sales volume during the same period of 2024. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 292 MBbls and 217 MBbls at September 30, 2025 and 2024, 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 nine months ended September 30, 2025, the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contributed $102.9 million of revenue to the Company’s total revenue for the nine months ended September 30, 2025, which is $4.1 million lower than the $107.0 million of revenue reported during the nine months ended September 30, 2024. The decrease in revenues was primarily due to a decrease in average realized sales price from $55.12 per Bbl during the nine months ended September 30, 2024 to $50.74 per Bbl during the same period in 2025. Sales volumes in Egypt remained relatively consistent at 2,027 MBbls and 1,941 MBbls during the nine months ended September 30, 2025 and 2024, respectively.

Canada

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $14.9 million of revenue to the Company’s total revenue for the nine months ended September 30, 2025, or a decrease of $9.6 million, compared to $24.5 million of revenue reported during the nine months ended September 30, 2024. The decrease in revenues was primarily due to lower average realized sales price received of $29.54 per Boe during the nine months ended September 30, 2025 compared to $37.29 per Boe received during the same period in 2024. Sales volumes in Canada decreased during the nine months ended September 30, 2025 to 506 MBoe in comparison to 656 MBoe in the same period in 2024.

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 noted, the FPSO ceased production in January 2025 and its refurbishment is currently underway in the shipyard. The FPSO is expected to return to service in 2026. The Company's Côte d’Ivoire segment contributed $18.4 million of revenue to the Company’s total revenue for the nine months ended September 30, 2025, or a decrease of $48.6 million, compared to $67.0 million of revenue reported during the nine months ended September 30, 2024. The decrease in revenues was primarily due to a decrease in sales volumes from 844 MBbls during nine months ended September 30, 2024 to 238 MBbls during the same

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period in 2025. In addition, the average realized sales price received of $77.36 per Bbl during the nine months ended September 30, 2025 was lower compared to $79.43 per Bbl received during the same period in 2024.

Production expenses decreased $11.8 million for the nine months ended September 30, 2025 to $115.1 million from $126.9 million for the same period in the prior year. The decrease was primarily driven by higher expenses in Gabon which includes customs costs and increased maintenance costs to enhance well productivity offset by a decrease in expenses in the Cote d’Ivoire segment. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the nine months ended September 30, 2025 increased to $24.63 per barrel from $23.51 per barrel for the nine months ended September 30, 2024.

Exploration expense for the nine months ended September 30, 2025 of $2.9 million was attributable to the purchase of seismic data to be used in Block 705 in Cote d’Ivoire and the costs associated with Blocks G and H in Gabon. Exploration costs incurred during the same period in 2024 was minimal.

Depreciation, depletion and amortization costs decreased $26.9 million, or approximately 25%, for the nine months ended September 30, 2025 to $79.1 million from $106.0 million during the same period in 2024. The decrease in depreciation, depletion and amortization expense is primarily related to the lower depletable costs in Gabon and Egypt. Also, since there was no production since January 2025 in Côte d’Ivoire, there was also no depletion expense recorded and therefore resulted in the decrease in the overall depletion expense for the period.

General and administrative expenses increased $5.2 million, or 24%, for the nine months ended September 30, 2025 to $26.4 million from $21.2 million during the same period in 2024. The increase in general and administrative expenses is primarily due to an increase in professional service fees, salaries and wages, and accounting and legal fees.

Credit losses and other decreased by approximately $4.7 million during the nine months ended September 30, 2025 compared to the same period in 2024. The decrease in credit losses and other for the nine months ended September 30, 2025, is primarily attributable to the higher allowance calculated during the first nine months of 2024 related to the Backdated Receivables, defined in Part I, Item 1, Note 10. Commitments and Contingencies to the unaudited condensed consolidated financial statements. The Backdated Receivables were settled as of March 31, 2025.

Derivative instruments gain (loss), net is attributable to our swaps and collars as discussed in Part I, Item 1, Note 8. Derivatives to the unaudited condensed consolidated financial statements. Derivative loss increased by $0.4 million to a loss of $0.8 million for the nine months ended September 30, 2025 from a loss of $0.4 million during the same period in 2024. Derivative losses for the nine months ended September 30, 2025 are 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 nine months ended September 30, 2025. Our derivative instruments currently cover a portion of our production through September 2026 for oil and through December 2026 for gas.

Interest expense, net was $6.2 million for the nine months ended September 30, 2025 compared to an expense of $2.6 million during the same period in 2024. The increase in net interest expense for the nine months ended September 30, 2025 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 $0.6 million for the nine months ended September 30, 2025 compared with an expense of $3.9 million during the same period in 2024. The decrease in other income (expense) was substantially due to transactions costs associated with the Svenska acquisition of $3.4 million that were incurred during the nine months ended September 30, 2024.

Income tax expense (benefit) for the nine months ended September 30, 2025 was an expense of $19.5 million which includes a $6.4 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, income taxes were $25.9 million for the period. Income tax expense for the nine months ended September 30, 2024 was $64.1 million. This expense is comprised of current tax expense of $72.7 million including a $1.2 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 $73.9 million for such 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”, or “XAF”), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of September 30, 2025, we had net monetary liabilities of $88.4 million (XAF $49.4 billion) denominated in XAF. At September 30, 2025, we estimate that a 10% weakening of the CFA relative to the U.S. dollar would have a $8.0 million reduction in the value of these net liabilities. For the nine months ended September 30, 2025, we had expenditures of approximately $61.0 million net to Vaalco), denominated in XAF.

Related to our Canadian operations, our currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars. At September 30, 2025, we estimate that a 10% decrease in the value of the Canadian dollar against the US dollar would decrease the value of the net monetary assets for the three months ended September 30, 2025 by approximately $0.2 million. Conversely, a 10% increase in the value of the Canadian dollar against the US dollar would increase the value of the net assets for the nine months ended September 30, 2025 by approximately $0.2 million.

We are also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while we are generally able to use the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. At September 30, 2025, we estimate that a 10% increase in the value of the Egyptian pound against the US dollar would decrease the cash value for the nine months ended September 30, 2025 of the net liabilities by $5.8 million. Conversely, a 10% decrease in the value of the Egyptian pound against the US dollar would decrease our US dollar cash value for the nine months ended September 30, 2025 by $4.8 million.

In Côte d'Ivoire, our currency exchange risk also relates primarily to certain cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities denominated in Swedish Krona. We estimate that a 10% increase in the value of the Swedish Krona against the US dollar would decrease the value of the net liabilities for the nine months ended September 30, 2025 by approximately $2.5 million. Conversely, a 10% decrease in the value of the Swedish Krona against the US dollar would decrease the value of the net liabilities for the nine months ended September 30, 2025 by approximately $2.0 million.

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

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.

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.

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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 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 September 30, 2025, the Company had open commodity derivative contracts covering our anticipated future production as follows:


		Settlement Period
Instrument	Index	October 2025 to December 2025		January 2026 to March 2026		April 2026 to June 2026		July 2026 to September 2026
Crude oil:




Collars	Dated Brent
Total volumes (Bbls)		480,000		400,000		360,000		75,000
Weighted average floor price ($/Bbl)		$	60.83	$	62.29	$	61.88	$	65.00
Weighted average ceiling price ($/Bbl)		$	67.81	$	68.63	$	67.95	$	71.00

Natural Gas:
Swaps	AECO 7A
Total volumes (GJs)(a)		214,000		150,000		—		—
Weighted average fixed price (CAD/GJ)		$	2.48	$	2.86	$	—	$	—

(a) One gigajoule (GJ) equals one billion joules (J). A gigajoule of natural gas is approximately 25.5 cubic meters standard conditions.

The table below presents commodity swaps entered into subsequent to September 30, 2025.


		Settlement Period
Instrument	Index	October 2025 to December 2025		January 2026 to March 2026		April 2026 to June 2026		July 2026 to September 2026		October 2026 to December 2026





Natural Gas:
Swaps	AECO 7A
Total volumes (GJs)(a)		25,000		75,000		150,000		150,000		50,000
Weighted average fixed price (CAD/GJ)		$	3.26	$	3.26	$	2.80	$	2.80	$	2.80

a) One gigajoule (GJ) equals one billion joules (J). A gigajoule of natural gas is approximately 25.5 cubic meters standard conditions.

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 three months and nine months ended September 30, 2025, however, no triggering events were identified and therefore no impairment was recorded at September 30, 2025.

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The Company estimates that a $5 decline in oil prices (with all other assumptions unchanged) could result in a non-cash impairment in excess of $100 million for certain asset groups. It is also reasonably possible that significant or prolonged declines in commodity prices, negative reserve revisions, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in material future impairment charges.

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 nine months ended September 30, 2025 as follows:


	2025 Sales Volumes (Mbls)	Decrease in Revenues (In Millions)		Decrease in Operating Income (Increase in Operating Loss) (In Millions)
Gabon	1,891	$	9.5	$	8.5
Egypt	2,027	$	10.1	$	6.0
Côte d'Ivoire	238	$	1.2	$	0.6
Canada	506	$	2.5	$	1.9
Consolidated	4,662

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, the prices received are based on NYMEX WTI (West Texas Intermediate) prices plus or minus a differential. Natural gas sales are based on 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, Cote 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 September 30, 2025, our primary exposure to interest rate risk resulted from our $60.0 million of outstanding borrowings under our 2025 RBL Facility. The borrowing accrues interest at a rate of 10.8% per annum which is based on the Term SOFR plus the applicable margin of 6.5% per annum. 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 September 30, 2025 would have resulted in an increase in interest expense of $0.2 million. There were no outstanding borrowings during the year ended December 31, 2024. 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

Our management, including our Principal Executive Officer and Principal Financial Officer, have 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 the evaluation of our disclosure controls and procedures, our Principal Executive Officer and Principal Financial Officer have concluded that, as a result of material weaknesses in our internal control over financial reporting identified in connection with the preparation and audit of our consolidated financial statements for the year ended December 31, 2024, our disclosure controls and procedures were not effective as of September 30, 2025.

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MATERIAL WEAKNESS IN INTERNAL CONTROL OVER FINANCIAL REPORTING

As previously disclosed in Part II, Item 9A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2024, Management previously identified the following material weaknesses in internal control over financial reporting:

•The Company had ineffective general information technology controls (“GITCs”) that support the consistent operation of the Company’s information technology (“IT”) systems, specific to its procure-to-pay system. As a result, automated process-level controls and manual controls dependent upon the accuracy and completeness of information derived from that IT system were also ineffective because they could have been adversely impacted; and

•The Company did not effectively design, implement, or operate process-level control activities related to its financial reporting process, specific to its procure-to-pay process.

After giving full consideration to the material weakness, and the additional analyses and other procedures we performed to ensure that our unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q were prepared in accordance with GAAP, our management has concluded that our unaudited condensed consolidated financial statements present fairly, in all material respects, our financial position, results of operations and cash flows for the periods disclosed in conformity with GAAP. We have developed and are implementing a remediation plan for the material weakness, which is described below.

MANAGEMENT’S PLAN FOR REMEDIATION OF THE MATERIAL WEAKNESS

As previously described in Part II, Item 9A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2024, we began implementing a remediation plan to address the material weaknesses mentioned above. The material weaknesses will not be considered remediated until the applicable controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively.

Although we intend to complete the remediation process as promptly as possible, we cannot at this time estimate how long it will take to remediate the material weaknesses described above. We may discover additional material weaknesses that require additional time and resources to remediate, and we may decide to take additional measures to address the material weaknesses or modify the remediation steps described above.

In addition, while certain of the activities described above have continued to enhance our internal control over financial reporting, certain of these newly designed controls have not operated effectively for a sufficient period of time to be able to conclude on effectiveness. We remain committed to continue investing significant time and resources and taking actions to remediate the material weaknesses in our internal control over financial reporting as we work to further enhance our control environment. Until these material weaknesses are remediated, we plan to continue to perform additional analyses and other procedures to ensure that our consolidated financial statements are prepared in accordance with U.S. GAAP.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Except for the activities taken related to the remediation of the material weaknesses described above, there have been no changes in our internal control over financial reporting during the three months ended September 30, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. 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.

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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 2024 Form 10-K. Except as set forth below, there have been no material changes in our risk factors from those described in our 2024 Form 10-K.

Provisions of our agreements could discourage an acquisition of us by a third-party.

Certain provisions of our production sharing contracts, joint operating agreements and other agreements could make it more difficult or more expensive for a third-party to acquire us or our assets, or may even prevent a third-party from acquiring us or our assets. For example, some of these agreements contain restrictions on assignments of our assets, including requirements to obtain consent from applicable counterparties, preemption rights and requirements to make bonus payments. In some cases, these restrictions apply to “indirect assignments.” By discouraging an acquisition of us or our assets by a third-party, these provisions could have the effect of deterring otherwise interested third-parties from proposing or consummating these acquisitions. This could deprive the holders of our common stock of an opportunity to sell their common stock at a premium over prevailing market prices.

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

Unregistered Sale of Equity Securities

There were no sales of unregistered securities during the three months ended September 30, 2025 that were not previously reported on a Current Report on Form 8-K.

ITEM 5. OTHER INFORMATION

10b5-1 Trading Arrangements

During the three months ended September 30, 2025, 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).
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

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SIGNATURE

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

VAALCO ENERGY, INC.

(Registrant)


By:						/s/ Ronald Bain
						Ronald Bain Chief Financial Officer (Duly authorized officer and Principal Financial Officer)

Dated: November 10, 2025

Form: 10-Q

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