Vaalco Energy Inc: Form 10-Q for the period ended Jun 30, 2025

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;
• 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, the conflict 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.

RECENT DEVELOPMENTS

Quarterly Cash Dividends

The Company paid a quarterly cash dividend of $0.0625 per share of common stock for the second quarter of 2025 ($0.25 annualized) on June 27, 2025 to stockholders of record at the close of business on May 23, 2025. The Company also announced its next quarterly cash dividend of $0.0625 per share of common stock for the third quarter of 2025 ($0.25 annualized) to be paid on September 19, 2025 to stockholders of record at close of business on August 22, 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 near the end of the third quarter of 2025, as we wait for the drilling rig to complete 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 the wells at both the Etame platform and at our Seent platform, as well as a re-drill and several 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.

Egypt

The drilling campaign in Egypt, which commenced in December 2024, continued through the second quarter of 2025. During the second quarter of 2025, we completed six wells. Three of the wells drilled in the second quarter of 2025 will be hydraulically fractured in the third quarter of 2025. Based on detailed analysis completed in the first quarter of 2025 to evaluate the well inventory potential, a series of workover re-completions, re-activations and well optimizations have also been carried out resulting in an incremental production gain.

Canada

In 2024, Vaalco drilled and completed five horizontal wells in Canada, with all laterals being greater than two miles long. These wells continue to meet production expectations and the Company is monitoring their longer-term performance for future drilling opportunities. In 2025, the Company has decided to defer the drilling of additional wells in Canada based on a reassessment of capital allocation priorities across the portfolio, ensuring that investment is directed toward projects with the highest expected returns.

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 now underway 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.

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 is still reviewing a Front End Engineering and Design study and is currently targeting a Final Investment Decision by the end of 2025.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

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

(in thousands)

The $29.7 million increase in net cash provided by operating activities during the six months ended June 30, 2025 compared to the six months ended June 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 $32.3 million for the six months ended June 30, 2025 compared to the same period of 2024 was primarily related to the overall decrease in accrued liabilities and accounts payable, as well as the increase in collections from the Egypt receivables, value added tax and other receivables.

The $58.8 million change in net cash used in investing activities during the six months ended June 30, 2025 compared to the six months ended June 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 six months ended June 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 used in financing activities during the six months ended June 30, 2025 included $13.1 million for dividend distributions, $6.9 million of payments for deferred financing costs and $6.3 million of principal payments on our finance leases, offset by $60.0 million in proceeds from borrowings under the 2025 RBL Facility. For the six months ended June 30, 2024, cash used in financing activities included $13.0 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 $4.2 million of principal payments on our finance leases partially offset by $0.5 million in proceeds from options exercised.

Capital Expenditures

For the six months ended June 30, 2025, we had accrual basis capital expenditures of $92.2 million compared to $46.5 million accrual basis capital expenditures for the same period in 2024. For the six months ended June 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 preparation of the FPSO dry dock project 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 and Fair Value to the unaudited condensed consolidated financial statements for further discussion.

Cash on Hand

At June 30, 2025, we had unrestricted cash of $67.9 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, 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 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 June 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 near the end of the third quarter of 2025. In Egypt, additional drilling and completion activity is expected in the second half 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 June 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.

Trends and Uncertainties

Geopolitical Conflict and Other Market Forces – The outbreak of armed conflict between Russia and Ukraine in February 2022 and the subsequent sanctions imposed on the Russian Federation has, and may continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets. The ongoing conflict has caused, and could continue to intensify, volatility in oil and natural gas prices, and the extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.

For example, shortly after the outbreak of the conflict through the year ended December 31, 2024 and ongoing into 2025, we noticed that the lead times associated with obtaining materials to support our operations and drilling activities have lengthened, leading to delays and, in most cases, prices for materials have increased. Management believes the ongoing war between Russia and Ukraine, the Houthis attacks on maritime vessels in the Red Sea region, conflicts in the Middle East and the related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy, as well as destabilizing impacts on the global oil and natural gas market. In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.

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.

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.

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.

We expect continued required reporting attention on climate change issues and emissions of greenhouse gases (“GHG”), including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion) and freshwater use as and when the UK Government confirms that UK listed businesses shall be required to comply with IFRS S2 Climate-Related Disclosures. These requirements replace the Task Force on Climate-related Financial Disclosures (“TCFD”) reporting requirements noted below.

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, 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.

US activity notwithstanding, for the past three years, the Company has refined its reporting in line with the recommendations of the 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.

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 June 30, 2025 Compared to the Three Months Ended June 30, 2024

Net income for the three months ended June 30, 2025 was $8.4 million compared to a net income of $28.2 million during the same period of 2024. See discussion below for changes in revenues and expenses.

Crude oil, natural gas and NGLs revenues decreased $19.9 million, or approximately 17%, to $96.9 million during the three months ended June 30, 2025 from $116.8 million during the same period in 2024. The revenue decrease is primarily attributable to lower revenues in our Côte d'Ivoire and Canada segments.

(in thousands)

The revenue changes in the three months ended June 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)

(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.

* 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 $58.6 million of revenue to the Company’s total revenue during the three months ended June 30, 2025, an increase of $4.9 million from the $53.7 million of revenue reported during the three months ended June 30, 2024. The increase in revenues is primarily due to a sales volume increase in Gabon from the 660 MBbls reported during the second quarter of 2024 to 900 MBbls for the three months ended June 30, 2025, offset by a lower average realized sales price received in Gabon of $65.02 per Bbl for three months ended June 30, 2025 compared to the $81.29 per Bbl average realized sales price received during the same period in 2024. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 54,776 barrels and 129,803 barrels at June 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 June 30, 2025, the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contributed $33.3 million of revenue to the Company’s total revenue for the three months ended June 30, 2025, which is slightly lower than the $35.5 million of revenue reported during the three months ended June 30, 2024. The decrease in revenues was primarily due to a decrease in average realized sales price from $55.19 per Bbl during the three months ended June 30, 2024 to $48.01 per Bbl during the same period in 2025. Sales volumes in Egypt remained relatively consistent at 693 MBbls and 643 MBbls, during the three months ended June 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 $4.7 million of revenue to the Company’s total revenue for the three months ended June 30, 2025, or a decrease of $5.7 million compared to $10.4 million of revenue reported during the three months ended June 30, 2024. The decrease in revenues was primarily due to lower average realized sales price received of $27.35 per Boe during the three months ended June 30, 2025 compared to the $41.68 per Boe received during the same period in 2024. Sales volumes in Canada decreased during the three months ended June 30, 2025 to 172 MBoe in comparison to 249 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. The Company's Côte d’Ivoire segment contributed $0.4 million of revenue to the Company’s total revenue during the three months ended June 30, 2025. As previously noted, the FPSO refurbishment is now underway in the shipyard. The FPSO is expected to return to service in 2026.

Production expenses decreased $12.1 million, or approximately 23%, for the three months ended June 30, 2025 to $40.4 million from $52.4 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 June 30, 2025 decreased to $22.85 per barrel from $29.68 per barrel for the three months ended June 30, 2024.

Exploration expense for the three months ended June 30, 2025 of $2.5 million was attributable to the purchase of seismic data to be used in Block 705 in Cote d’Ivoire. There were no exploration costs incurred during the same period in 2024.

Depreciation, depletion and amortization costs decreased $4.9 million, or approximately 15%, for the three months ended June 30, 2025 to $28.3 million from $33.1 million during the same period in 2024. Since there was no production during the three months ended June 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 slightly increased $0.9 million, or 12%, for the three months ended June 30, 2025 to $8.5 million from $7.6 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 $3.3 million during the three months ended June 30, 2025 compared to the same period in 2024. The decrease in credit losses and other is primarily attributable to the higher allowance calculated during the second quarter 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 and Fair Value to the unaudited condensed consolidated financial statements. Derivative gain increased by $0.1 million to a gain of $0.4 million for the three months ended June 30, 2025 from a gain of $0.3 million during the same period in 2024. Derivative gains for the three months ended June 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 June 30, 2025. Our derivative instruments currently cover a portion of our production through July 2026 for oil and through March 2026 for natural gas.

Interest expense, net was $2.6 million for the three months ended June 30, 2025 compared to an expense of $1.1 million during the same period in 2024. The increase in net interest expense for the three months ended June 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 decreased by $2.3 million to an income of $0.4 million for the three months ended June 30, 2025 from a $2.0 million expense during the same period in 2024. Other income (expense), net, normally consists primarily of foreign currency gains and losses. However, during the three months ended June 30, 2024, there was a $1.7 million expense related to transactions costs associated with the Svenska acquisition.

Income tax expense (benefit) for the three months ended June 30, 2025 was an expense of $7.0 million which includes a $3.1 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, income taxes were $10.1 million for the period. Income tax expense for the three months ended June 30, 2024 was an expense of $9.3 million. This expense is comprised of current tax expense of $10.4 million including a $1.1 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, current income taxes were $10.4 million for the period.

Six Months Ended June 30, 2025 Compared to the Six Months Ended June 30, 2024

Net income for the six months ended June 30, 2025 was $16.1 million compared to a net income of $35.8 million during the same period of 2024. See discussion below for changes in revenues and expenses.

Crude oil, natural gas and NGLs revenues decreased $9.7 million, or approximately 4%, to $207.2 million during the six months ended June 30, 2025 from $216.9 million during the same period in 2024. The revenue decrease is primarily due to lower revenues in Egypt and Canada.

(in thousands)

31

The revenue changes in the six months ended June 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)

(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.

* 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 $110.8 million of revenue to the Company’s total revenue during the six months ended June 30, 2025, a slight decrease of $0.4 million from the $111.2 million of revenue reported during the six months ended June 30, 2024. The decrease in revenues is primarily due to the lower average realized sales price received in Gabon of $71.04 per Bbl for six months ended June 30, 2025 compared to $83.61 per Bbl average realized sales price received during the same period in 2024 offset by an increase in sales volume in Gabon to 1,558 MBbls for the six months ended June 30, 2025 from the 1,330 MBbls sales volume during the same period of 2024. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 54,776 barrels and 129,803 barrels at six months ended June 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 six months ended June 30, 2025, the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contributed $67.2 million of revenue to the Company’s total revenue for the six months ended June 30, 2025, which is $5.2 million lower than the $72.4 million of revenue reported during the six months ended June 30, 2024. The decrease in revenues was primarily due to a decrease in average realized sales price from $56.43 per Bbl during the six months ended June 30, 2024 to $50.34 per Bbl during the same period in 2025. Sales volumes in Egypt remained relatively consistent at 1,334 MBbls and 1,284 MBbls during the six months ended June 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 $10.9 million of revenue to the Company’s total revenue for the six months ended June 30, 2025, or a decrease of $5.2 million, compared to $16.1 million of revenue reported during the six months ended June 30, 2024. The decrease in revenues was primarily due to lower average realized sales price received of $31.04 per Boe during the six months ended June 30, 2025 compared to $37.46 per Boe received during the same period in 2024. Sales volumes in Canada decreased during the six months ended June 30, 2025 to 351 MBoe in comparison to 429 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. The Company's Côte d’Ivoire segment contributed $18.4 million of revenue to the Company’s total revenue for the six months ended June 30, 2025, or an increase of $1.2 million, compared to $17.2 million of revenue reported during the six months ended June 30, 2024. The increase in revenues was primarily due to an increase in sales volumes from 211 MBbls during six months ended June 30, 2024 to 238 MBbls during the same period in 2025. The increase in sales volumes is offset by lower average realized sales price received of $77.36 per Boe during the six months ended June 30, 2025 compared to $81.59 per Boe received during the same period in 2024.

Production expenses increased $0.7 million for the six months ended June 30, 2025 to $85.2 million from $84.5 million for the same period in the prior year. The increase was primarily driven by higher expenses in Gabon which includes customs costs of approximately $4.7 million and increased maintenance costs to enhance well productivity partially 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 six months ended June 30, 2025 decreased to $24.43 per barrel from $25.96 per barrel for the six months ended June 30, 2024.

Exploration expense for the six months ended June 30, 2025 of $2.5 million was attributable to the purchase of seismic data to be used in Block 705 in Cote d’Ivoire. Exploration costs incurred during the same period in 2024 was minimal.

Depreciation, depletion and amortization costs decreased $0.4 million, or approximately 1%, for the six months ended June 30, 2025 to $58.6 million from $59.0 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.

General and administrative expenses slightly increased $3.2 million, or 23%, for the six months ended June 30, 2025 to $17.5 million from $14.3 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 $5.2 million during the six months ended June 30, 2025 compared to the same period in 2024. The decrease in credit losses and other for the six months ended June 30, 2025, is primarily attributable to the higher allowance calculated during the first six 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 and Fair Value to the unaudited condensed consolidated financial statements. Derivative loss decreased by $0.9 million to a gain of $0.3 million for the six months ended June 30, 2025 from a loss of $0.6 million during the same period in 2024. Derivative gains for the six months ended June 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 six months ended June 30, 2025. Our derivative instruments currently cover a portion of our production through July 2026 for oil and through March 2026 for gas.

Interest expense, net was $3.9 million for the six months ended June 30, 2025 compared to an expense of $2.1 million during the same period in 2024. The increase in net interest expense for the six months ended June 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 decreased by $3.1 million compared to an expense of $0.7 million for the six months ended June 30, 2025 from a $3.8 million expense during the same period in 2024. The decrease in other income (expense) was substantially due to transactions costs associated with the Svenska acquisition of $3.1 million that were incurred during the six months ended June 30, 2024.

Income tax expense (benefit) for the six months ended June 30, 2025 was an expense of $23.1 million which includes a $2.4 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding this impact, income taxes were $25.4 million for the period. Income tax expense for the six months ended June 30, 2024 was an expense of $31.5 million. This expense is comprised of current tax expense of $26.4 million including a $0.6 million adverse 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 $30.9 million for the period.

MARKET RISK

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

FOREIGN EXCHANGE RISK

Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the “Central African CFA Franc” or “XAF”), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of June 30, 2025, we had net monetary liabilities of $145.6 million (XAF $81.5 billion) denominated in XAF. Using month-end cash balances converted at month-end foreign exchange rates at June 30, 2025, we estimate that a 10% weakening of the CFA relative to the U.S. dollar would have a $13.2 million reduction in the value of these net liabilities. For the six months ended June 30, 2025, we had expenditures of approximately $48.1 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. Using month-end cash balances converted at month-end foreign exchange rates at June 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 assets for the three months ended June 30, 2025 by approximately $0.6 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 six months ended June 30, 2025 by approximately $0.8 million.

We are also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while we are generally able to use the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates at June 30, 2025, we estimate that a 10% increase in the value of the Egyptian pound against the US dollar would increase the cash value for the six months ended June 30, 2025 by $7.5 million. Conversely, a 10% decrease in the value of the Egyptian pound against the US dollar would decrease our US dollar cash value for the six months ended June 30, 2025 by $6.1 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 increase the value of the net liabilities for the six months ended June 30, 2025 by approximately $9.7 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 six months ended June 30, 2025 by approximately $7.9 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.

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

(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 June 30, 2025.

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 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 six months ended June 30, 2025, however, no triggering events were identified and therefore no impairment was recorded at June 30, 2025. However, further decline in commodity prices will result in declined future cash flows which would lead to oil and gas properties to be at risk for future impairment.

It is also reasonably possible that prolonged low or further decline in commodity prices, negative reserve revisions, changes to the Company's drilling plans in response to lower prices or increases in drilling or operating costs would 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 six months ended June 30, 2025 as follows:

With respect to our crude oil sales in Gabon, Egypt and Côte d'Ivoire the price 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 June 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 June 30, 2025 would have resulted in an increase in interest expense of $0.06 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.

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 June 30, 2025.

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 June 30, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.