VAALCO Energy Inc.

11/09/2026 | Press release | Distributed by Public on 11/09/2026 15:45

Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this "Quarterly Report") includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and may also include forward-looking information within the meaning defined under applicable Canadian securities laws (collectively, "forward-looking statements"), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Quarterly Report that address activities, events or developments that we expect or anticipate may occur in the future, including, without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, payment of dividends and plans and objectives of management for future operations are forward-looking statements. When we use words such as "anticipate," "believe," "estimate," "expect," "intend," "forecast," "outlook," "aim," "target," "will," "could," "should," "may," "likely," "plan" and "probably" or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:
•the impact of world health events, including any related impact on global demand for crude oil and crude oil prices, potential difficulties in obtaining additional liquidity, when and if needed, disruptions in global supply chains and disruptions to our workforce;
•the impact of any future production quotas imposed by Gabon, as a member of the Organization of the Petroleum Exporting Countries ("OPEC"), as a result of agreements among OPEC, Russia and other allied producing countries with respect to crude oil production levels;
•the impact of the wide-ranging policy changes and numerous executive actions issued by the current U.S. presidential administration on topics including international trade, imposition of trade tariffs, energy resources, corporate taxes, global climate change initiatives, employment practices, corporate compliance programs, environmental regulations, as well as other matters;
•the macroeconomic, regulatory or other potential effects of a prolonged U.S. government shutdown;
•volatility of, and declines and weaknesses in crude oil, natural gas and natural gas liquids ("NGLs") prices, as well as our ability to offset volatility in prices through the use of hedging transactions;
•the discovery, acquisition, development and replacement of crude oil, natural gas and NGLs reserves;
•impairments in the value of our crude oil, natural gas and NGLs assets;
•future capital requirements;
•our ability to maintain sufficient liquidity in order to fully implement our business plan;
•our ability to generate cash flows that, along with our cash on hand and our 2025 RBL facility, will be sufficient to support our operations and cash requirements;
•the ability of the BWE Consortium to successfully execute its business plan;
•our ability to attract capital or obtain debt financing arrangements;
•our ability to pay the expenditures required in order to develop certain of our properties;
•operating hazards inherent in the exploration for and production of crude oil, natural gas and NGLs;
•difficulties encountered during the exploration for and production of crude oil, natural gas and NGLs;
•the impact of competition;
•our ability to identify and complete complementary opportunistic acquisitions;
•our ability to effectively integrate assets and properties that we acquire into our operations;
•weather conditions;
•the uncertainty of estimates of crude oil and natural gas;
•currency exchange rates and regulations;
•unanticipated issues and liabilities arising from non-compliance with environmental regulations;
•the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon currently being conducted by the government of Gabon;
•our limited control over the assets we do not operate;
•the availability and cost of seismic, drilling and other equipment;
•difficulties encountered in measuring, transporting and delivering crude oil, natural gas and NGLs to commercial markets;
•timing and amount of future production of crude oil, natural gas and NGLs;
•hedging decisions, including whether or not to enter into derivative financial instruments;
•general economic conditions, including any future economic downturn, the impact of inflation or tariffs, disruptions in financial credit and other disruptions resulting from geo-political events such as the Russia/Ukraine war, conflicts in the Middle East, including the United States-Israel-Iran war, trade tensions between the U.S. and China and U.S. military operations in Venezuela;
•our ability to enter into new customer contracts;
•changes in customer demand and producers' supply;
•actions by governments and other significant actors with respect to events occurring in the countries in which we operate;
•actions by our joint venture partners;
•compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;
•the outcome of any governmental audit;
•the anticipated impact on our business and operations of the OBBBA (defined below); and
•actions of operators of our crude oil, natural gas and NGLs properties.
The information contained in this Quarterly Report and the information set forth under the heading "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2025 ("2025 Form 10-K"), identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Quarterly Report and the 2025 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Quarterly Report.
Our forward-looking statements speak only as of the date the statements are made and reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements, express or implied, are expressly qualified in their entirety by this "Cautionary Statement Regarding Forward-Looking Statements," which constitute cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Quarterly Report.
INTRODUCTION
Vaalco is a Houston, Texas-based, African-focused independent energy company with a strong production and reserve portfolio of assets in Gabon, Egypt, Côte d'Ivoire, Equatorial Guinea, and, prior to the Canada Assets Divestment, producing properties in Canada. We are currently engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.
Business Environment and Outlook
The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment and uncertainties. These factors, and any changes to these factors, among others, could have a material adverse impact on our future revenues and overall profitability. See Part II, Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2025 Form 10-K for further discussion of Trends and Uncertainties.
Commodity Prices - Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts of ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies, and actions taken by foreign oil and gas producing nations, including OPEC+. Changes in oil prices could result in adjustments to capital investment levels and allocation, which impact our production volumes.
Geopolitical Conflict and Other Market Forces - The Company continues to monitor geopolitical developments globally, and specifically in Europe, the Middle East, Africa, and North America, where they have the potential to impact operational continuity and market dynamics. Global markets are also experiencing volatility and uncertainty connected to the Russia-Ukraine war, conflicts in the Middle East, including the United States-Israel-Iran war and the U.S. intervention in Venezuela. Additionally, geopolitical tensions and localized disruptions persist in parts of West Africa, where we hold significant producing and development interests, which require ongoing vigilance regarding political, economic, and security risks. The duration and impact of these ongoing armed conflicts, and the potential of these conflicts spreading to more regions are uncertain and could adversely affect the global economy, financial markets, our customers and in turn, us.
U.S. Tariffs and Global Trade Policies - In 2025, the U.S. administration enacted sweeping trade legislation, including significant tariff increases on industrial goods, energy-related equipment, and certain critical minerals, with a stated intent to prioritize domestic manufacturing and energy security. Global trade policy continues to evolve and the ultimate impact of recent developments with respect to U.S. tariffs is unclear. While we do not maintain U.S.-based production assets, our operations on the continent of Africa rely on equipment, services and materials that are often sourced, engineered, or consolidated through the United States or through U.S.-aligned trading routes. As a result, we may experience increased costs and longer lead times for the procurement and delivery of drilling and production equipment, particularly if suppliers adjust pricing in response to increased duties or if we are required to diversify sourcing channels. These impacts could affect the timing, cost structure and execution risk of certain development activities, especially in frontier offshore environments.
Enactment of the One Big Beautiful Bill Act of 2025 - On July 4, 2025, the budget reconciliation bill known as the One Big Beautiful Bill Act of 2025 ("OBBBA") was signed into law, which includes significant changes to federal tax law and other regulatory provisions that may impact the Company. Among other provisions, the OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017. The legislation has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027. The impact of provisions effective in 2025 and through the date of this filing is not material and the Company is still assessing the impact of provisions that are not yet effective.
As a company, we remain focused on our overall business strategy to maximize the value of our current resources and expand into new development opportunities across our strategically complementary asset base. We intend to accelerate shareholder returns and increase shareholder value by controlling operating costs and capital expenditures, maximizing reserve recoveries and making disciplined strategic accretive acquisitions that meet our strategic and financial objectives. We believe that our quality portfolio, strong management and technical expertise specific to the markets in which we operate, and our ongoing focus on maintaining a competitive cost structure and disciplined capital allocation framework, position us to achieve our business strategy and navigate a variety of commodity price environments. Over the past several years, we have delivered on our focused strategy and believe we will continue to do so with the organic growth programs across our diversified portfolio over the coming years.
Recent Operational Updates
Gabon
The Company successfully drilled and completed the ETBNM-3 gas-supply well from the SEENT platform. The well was directionally drilled adjacent to a discovery well and targeted gas and condensate resources in the Dentale D15 reservoir. The well was brought online, and the natural gas produced is being utilized for field operations, reducing reliance on higher-cost diesel transported to the field by vessel. The Company subsequently moved the drilling rig to a new slot on the SEENT platform, where it drilled and completed the ETSEM-3H development well in an attic position within the SE Etame field. The well has been brought online and is currently producing. The completion of ETSEM-3H concluded the Phase Three drilling campaign, and the drilling rig was subsequently demobilized from the field.
Overall, the Phase Three drilling campaign included the drilling and completion of four development wells and one gas-supply well.
In January 2026, the BWE Consortium completed its 3D seismic campaign across the Niosi and Guduma blocks. Processing and interpretation of the seismic data remain ongoing.
Egypt
The 2026 drilling campaign in Egypt, which commenced in May 2026, continued during the third quarter with five development wells drilled and completed. Drilling also commenced on two additional wells during the quarter that were completed in October 2026. Vaalco now plans to maintain an ongoing drilling program in Egypt into 2027.
We also successfully executed a series of workovers, well interventions, well reactivations, water shut-off treatments, and production optimization activities that are contributing to the organic growth of our production and reserves.
Côte d'Ivoire
Following the completion of its planned dry dock refurbishment in February 2026, the FPSO Baobab Ivoirien returned to Côte d'Ivoire and was successfully reconnected to field infrastructure in early April 2026. Production resumed from all producer wells in June 2026, and the first crude oil lifting was completed in August 2026. The Phase Five drilling campaign commenced following the batch-setting of top-holes by the operator. After the top-hole sections of all wells are drilled, the wells will then be completed and placed on production sequentially. The first production well is expected to come online near the end of 2026. The campaign is expected to support future production growth and the continued development of the main Baobab field in Block CI-40.
The Company is also the operator of exploration license CI-705 with a 70% working interest. Following completion of the first exploration phase, the Company elected to proceed with the second exploration phase, for which government approval has been granted. Under the PSC, the second exploration phase requires the Company to relinquish approximately 25% of the Phase 1 Block CI-705 area and fulfill certain minimum work and investment commitments, including the reprocessing of 3D seismic data, geological and geophysical studies, and the drilling of one firm exploration well.
In February 2026, the Company became the operator with a 60% working interest in the Kossipo field on the CI-40 Block with a field development plan ("FDP") being actively progressed toward completion in the first half of 2027 Vaalco continues analyzing ocean bottom node ("OBN") seismic data that was recently acquired which is helping to drive and de-risk the Company's updated evaluation as it progresses with the FDP.
Equatorial Guinea
We own a 60% working interest in an undeveloped portion of Block P offshore Equatorial Guinea where we are the designated operator. We have an existing plan of development of the Venus field discovery on Block P, which focuses on key areas of drilling evaluations, facilities design, market inquiries and metocean review. The Company has completed the initial Front End Engineering and Design study that confirmed the viability of the development concept and is currently evaluating alternative technical solutions which may deliver enhanced economic value. Work is progressing toward Final Investment Decision in the fourth quarter of 2026.
Canada
As discussed above, in February 2026, the Company completely exited its Canadian oil and gas operations. Please see Part I, Item 1, Note 3. Acquisition and Divestment to the unaudited condensed consolidated financial statements for further discussion on the sale of the Canada operating assets.
CAPITAL RESOURCES AND LIQUIDITY
Our primary sources of liquidity have been cash flows from operations, cash on hand and available borrowing capacity under the 2025 RBL Facility, and our primary use of cash has been to fund capital expenditures for development activities. At September 30, 2026, we had unrestricted cash of $51.3 million. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and our 2025 RBL Facility to support our current cash requirements during the next 12 months and beyond, including the drilling programs, dividend payments, Merged Concession Agreement, abandonment funding, as well as transaction expenses and capital and operational costs associated with our business segments' operations. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or pay dividends, or other strategic transactions depends on operating and economic conditions, some of which are beyond our control. In the event additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, on expected timelines, or at all. We continue to evaluate the use of available cash, including opportunistic acquisitions and other growth initiatives, and assess whether additional liquidity sources, including equity and/or debt financing, would be appropriate to fund such activities.
Cash Flows
Our cash flows for the nine months ended September 30, 2026 and 2025 are as follows:
Nine Months Ended September 30,
2026 2025 Change in 2026 over 2025
(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities $ 86,864 $ 86,969 $ (105)
Net change in operating assets and liabilities 2,939 (19,475) 22,414
Net cash provided by operating activities 89,803 67,494 $ 22,309
Net cash used in investing activities (243,050) (155,762) (87,288)
Net cash provided by financing activities 145,639 22,603 123,036
Effects of exchange rate changes on cash 4 53 (49)
Net change in cash, cash equivalents and restricted cash $ (7,604) $ (65,612) $ 58,008
The $22.3 million increase in net cash provided by operating activities during the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 was primarily attributable to higher crude oil, natural gas and natural gas liquids sales and favorable changes in working capital and other assets and liabilities. These increases were partially offset by cash settlements paid on matured derivative contracts and higher exploration expenses, including the acquisition of seismic data and costs associated with drilling activities in Gabon.
Net cash used in investing activities during the nine months ended September 30, 2026 was primarily attributable to $268.5 million for expenditures associated with the FPSO Baobab Ivoirien Renovation, as well as the development drilling programs in Gabon, Côte d'Ivoire and Egypt, offset by cash proceeds of $25.5 million from the Canada Assets Divestment. For the nine months ended September 30, 2025, cash used in investing activities was due to costs associated with the development drilling programs in Egypt, as well as maintenance, project costs and long lead items for Gabon and Côte d'Ivoire.
Net cash provided by financing activities during the nine months ended September 30, 2026 primarily consisted of $179.0 million of proceeds from borrowings under the 2025 RBL Facility, offset by cash outflows of $20.1 million for dividend distributions, $2.2 million for deferred financing costs, $2.0 million to satisfy employee withholding tax obligations related to vested equity awards, and $9.1 million of principal payments on finance lease obligations. For the nine months ended September 30, 2025, cash provided by financing activities related to $60.0 million in proceeds from borrowing under the 2025 RBL Facility, offset by $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.
2025 Facility Agreement and Available Credit
For information on our 2025 Facility Agreement and available credit, see Part I, Item 1, Note 10. Debt to the unaudited condensed consolidated financial statements.
Merged Concession Agreement
For information on the Merged Concession Agreement, see Part I, Item 1, Note 9. Commitments and Contingencies to the unaudited condensed consolidated financial statements.
Commodity Price and Interest Rate Hedging
We actively manage commodity price risk by entering into derivative transactions that help mitigate the impact of volatility in crude oil, NGL and natural gas prices on our cash flows and operating results; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices. We have entered into derivative contracts primarily with counterparties that are also lenders under the 2025 RBL Facility. If aggregate borrowings exceed 35% of specified thresholds, our 2025 RBL Facility requires us to enter into commodity price hedge positions establishing certain minimum fixed prices for anticipated future production.
The Company is exposed to interest rate risk through borrowings under its 2025 RBL Facility, which bear interest at variable rates based on Term SOFR plus an applicable margin. During the year, we entered into a zero-cost collar to partially mitigate our exposure to variability in interest payments resulting from changes in interest rates.
See Part I, Item 1, Note 7. Derivatives to the unaudited condensed consolidated financial statements for further discussion.
Cash Requirements
Our material cash requirements generally consist of capital projects, finance and operating leases, dividend payments, Merged Concession Agreement and abandonment funding, each of which is discussed in further detail below.
Capital Projects and Expenditures - For the nine months ended September 30, 2026, we had accrual basis capital expenditures of $256.3 million compared to $147.6 million of accrual basis capital expenditures for the same period in 2025. Capital spending during the nine-month period ended September 30, 2026, primarily reflected development activities associated with the Phase Three drilling campaign in Gabon, refurbishment and reconnection activities relating to the FPSO Baobab Ivoirien in Côte d'Ivoire, Phase Five drilling campaign in Côte d'Ivoire, exploration expenses attributable to Gabon and costs incurred in connection with the 3D seismic campaign across the Niosi and Guduma blocks.
See "Recent Operational Updates" above for additional information regarding our capital projects.
Abandonment Funding - Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the extension of the Etame PSC, annual funding payments are spread over the periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. At September 30, 2026, the balance of the abandonment fund was $10.7 million ($6.3 million, net to Vaalco) on an undiscounted basis. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under "Other noncurrent assets" in the "Abandonment funding" line item of the unaudited condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.
Leases - We are a party to several operating and financing lease arrangements, including operating leases for the corporate office, a drilling rig, rental of marine vessels and a helicopter, warehouse and storage facilities, equipment and financing lease agreements for the FSO, generators and turbines used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations in Egypt. The annual costs of these leases are significant to us.
Merged Concession Agreement - Under the Merged Concession Agreement, we have minimum financial work commitments of $50.0 million for each five-year period of the primary development term, commencing on February 1, 2020. Through September 30, 2026, 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. See Part I, Item 1, Note 9. Commitments and Contingencies to the unaudited condensed consolidated financial statements for additional information.
Drilling Rig Commitment - The Company entered into the Bareboat Charter for its Phase Three drilling campaign in Gabon. Pursuant to the Bareboat Charter, the Company also entered into a service agreement with a third party for purposes of maintaining and operating the drilling rig on its behalf. The Bareboat Charter and the service agreement commenced in November 2025 and have a noncancelable period of 300 days plus five single well options. The Bareboat Charter and the service agreement stipulate fixed day rates and other variable payments. The drilling rig was demobilized in October 2026 following the completion of the Phase Three drilling campaign.
BWE Consortium - We are a member of the BWE Consortium that was awarded the licenses for the Niosi Marin and Guduma Marin exploration blocks in Gabon. These licenses are covered by PSCs entered into with the Gabonese Government. These PSCs will have two exploration periods totaling eight years which may be extended by an additional two years. In January 2026, the BWE Consortium completed its 3D seismic campaign across the Niosi and Guduma blocks. Processing and interpretation of the seismic data remain ongoing. During the first exploration period, the joint owners have also committed to drilling exploration wells on both blocks. Under the terms of the BWE Consortium PSC, the Company holds a 37.5% non-operating working interest in these licenses.
Dividend Policy - Our Board of Directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter, which commenced in the first quarter of 2023. Payment of future dividends, if any, will be at the discretion of the Board of Directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Quarterly Cash Dividends
The Company paid a quarterly cash dividend of $0.0625 per share of common stock for the third quarter of 2026 ($0.25 annualized) on September 22, 2026 to stockholders of record at the close of business on August 21, 2026. The Company also announced its next quarterly cash dividend of $0.0625 per share of common stock for the fourth quarter of 2026 ($0.25 annualized) to be paid on December 22, 2026 to stockholders of record at the close of business on November 20, 2026.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
There have been no material changes to our critical accounting policies and estimates subsequent to December 31, 2025. For a discussion of the Company's critical accounting policies for the fiscal year ended December 31, 2025, please see our 2025 Form 10-K.
NEW ACCOUNTING STANDARDS
See Part I, Item 1, Note 2. New Accounting Standards to the unaudited condensed consolidated financial statements.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2026 Compared to the Three Months Ended September 30, 2025
Net loss for the three months ended September 30, 2026 was $39.8 million compared to a net income of $1.1 million during the same period in 2025. See discussion below for changes in revenues and expenses.
Crude oil, natural gas and NGLs revenues increased $86.0 million, or approximately 141%, to $147.0 million during the three months ended September 30, 2026 from $61.0 million during the same period in 2025. The increase in revenue is primarily attributable to higher realized sales prices per barrel along with an increase in sales volumes.
Three Months Ended September 30, Increase/(Decrease)
2026 2025
(in thousands)
Net crude oil, natural gas, and NGLs sales volume (MBoe) 1,698 1,180 518
Average crude oil, natural gas and NGLs sales price (per Boe) $ 83.64 $ 51.26 $ 32.38
Average Dated Brent spot price* ($/Bbl) $ 96.30 $ 69.04 $ 27.26
Net crude oil, natural gas, and NGLs revenue $ 146,975 $ 61,007 $ 85,968
Operating costs and expenses:
Production expense 44,978 29,872 15,106
Exploration expense 4,814 353 4,461
Depreciation, depletion and amortization 43,354 20,555 22,799
Loss on sale of assets 41 - 41
General and administrative expense 9,048 8,845 203
Credit losses and other 468 484 (16)
Total operating costs and expenses 102,703 60,109 42,594
Operating income 44,272 898 43,374
Other expense, net (63,797) (3,393) (60,404)
Loss before income taxes (19,525) (2,495) (17,030)
Income tax (benefit) expense 20,311 (3,596) 23,907
Net income (loss) $ (39,836) $ 1,101 $ (40,937)
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.
Crude oil, natural gas and NGLs revenues:
Gabon
Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. Total revenue from our Gabon segment was $73.8 million during the three months ended September 30, 2026, an increase of $52.5 million from the $21.3 million of revenue reported during the three months ended September 30, 2025. The increase in revenues is primarily due to a higher average realized sales price received in Gabon of $103.95 per Bbl for the three months ended September 30, 2026 compared to the $62.40 per Bbl average realized sales price received during the same period in 2025. Sales volumes also increased to 663 MBbls for the three months ended September 30, 2026 from the 333 MBbls reported during the third quarter of 2025. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 226 MBbls and 292 MBbls at September 30, 2026 and 2025, respectively.
Egypt
Crude oil in Egypt is 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, 2026, all crude oil sales were made directly to EGPC. Revenue from our Egypt segment increased to $45.3 million during the three months ended September 30, 2026 from $35.7 million during the comparable period in 2025. The increase in revenues was primarily driven by a higher average realized sales price, which increased to $64.05 per Bbl from $51.51 per Bbl in the same period in the prior year and by slightly higher sales volumes of 708 MBbls compared to 693 MBbls during the three months ended September 30, 2025.
Côte d'Ivoire
Crude oil production from the Côte d'Ivoire assets is marketed under an agreement with an international oil trading company that markets and sells cargoes to purchasers, primarily refineries, worldwide. As previously discussed, the FPSO Baobab Ivoirien ceased production in January 2025 to undergo a planned refurbishment program, which was completed in February 2026. Following completion of the refurbishment, the FPSO Baobab Ivoirien was reconnected to field infrastructure and production resumed from all producing wells. The first crude oil lifting occurred in August 2026. Revenue from the Côte d'Ivoire assets for the three months ended September 30, 2026 was $27.8 million, reflecting total sales volumes of 328 MBbls at an average realized sales price of $84.94 per Bbl. No crude oil sales were recorded during the three months ended September 30, 2025, as production remained suspended while the FPSO Baobab Ivoirien underwent refurbishment. At September 30, 2026, Côte d'Ivoire's share of crude oil inventory was approximately 156 MBbls.
Canada
Prior to the Canada Assets Divestment, crude produced in Canada was normally sold through pipelines to a third party. During the three months ended September 30, 2025, the Company's Canadian segment reported revenues of $4.0 million from sales volumes of 155 MBoe, reflecting an average realized sales price of $26.13 per Boe.
Production expenses increased by $15.1 million, or approximately 51%, for the three months ended September 30, 2026 to $45.0 million from $29.9 million for the same period in the prior year. The increase was primarily attributable to higher production expenses in our Gabon, Egypt and Côte d'Ivoire segments due to higher chemical and fuel costs, partially offset by lower production expenses resulting from the Canada Assets Divestment and the change in oil inventory adjustments in Gabon and Côte d'Ivoire. Production expenses associated with unsold crude oil inventory are capitalized and included in inventory, and are subsequently expensed when oil inventory is sold. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended September 30, 2026 increased to $26.44 per barrel from $25.23 per barrel for the three months ended September 30, 2025.
Exploration expense for the three months ended September 30, 2026 was $4.8 million and was primarily related drilling activities in Gabon. Exploration expense for the three months ended September 30, 2025 was $0.4 million, consisting primarily of costs incurred for the acquisition of additional seismic data for Block 705 in Côte d'Ivoire and for exploration activities related to the Niosi and Guduma blocks in Gabon.
Depreciation, depletion and amortization costs increased by $22.8 million, or approximately 111%, for the three months ended September 30, 2026 to $43.4 million from $20.6 million during the same period in 2025. The increase in depreciation, depletion and amortization expense is primarily related to the higher sales volumes in Gabon and Côte d'Ivoire, partially offset by a decrease in depletable costs as a result of the Canada Assets Divestment.
General and administrative expenses increased by $0.2 million, or 2%, for the three months ended September 30, 2026 to $9.0 million from $8.8 million during the same period in 2025. The increase in general and administrative expenses was primarily a result of higher legal and professional fees.
Credit losses and other remained relatively consistent for the three months ended September 30, 2026 compared to the same period in 2025 and primarily reflected allowance charges associated with joint venture partners and other receivables.
Commodity derivative instruments gain (loss), net is attributable to our collars, puts and swaps as discussed in Part I, Item 1, Note 7. Derivatives to the unaudited condensed consolidated financial statements. During the three months ended
September 30, 2026, we recognized a net derivative loss on commodity derivative contracts of $57.0 million compared to a net derivative loss of $1.1 million during the same period in 2025. The increase in net derivative loss was primarily attributable to increases in Dated Brent crude oil prices relative to the applicable strike prices of our derivative instruments, as well as increased derivative positions entered into during the current year compared to the prior year. Our derivative instruments currently cover a portion of our oil production through December 2027.
Interest expense, net was $5.6 million for the three months ended September 30, 2026 compared to $2.3 million for the same period in 2025. The increase was primarily attributable to increased borrowings under the 2025 RBL Facility and higher amortization of debt issue costs and commitment fees, partially offset by interest income. Interest expense, net also included an unrealized gain of $0.1 million related to changes in the fair value of our interest rate derivative instrument.
Other income (expense), net was a net expense of $1.2 million for the three months ended September 30, 2026 compared to a net income of less than $0.1 million during the same period in 2025. Other income (expense), net, primarily consists of foreign currency gains and losses.
Income tax expense for the three months ended September 30, 2026 was $20.3 million, which includes a $4.1 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind. Income tax expense 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.
Nine Months Ended September 30, 2026 Compared to the Nine Months Ended September 30, 2025
Net loss for the nine months ended September 30, 2026 was $91.2 million compared to a net income of $17.2 million during the same period in 2025. See discussion below for changes in revenues and expenses.
Crude oil, natural gas and NGLs revenues increased $76.5 million, or approximately 29%, to $344.7 million during the nine months ended September 30, 2026 from $268.2 million during the same period in 2025. The revenue increase is primarily attributed to higher average realized sales prices per barrel, partially offset by slightly lower sales volumes.
Nine Months Ended September 30, Increase/(Decrease)
2026 2025
(in thousands)
Net crude oil, natural gas, and NGLs sales volume (MBoe) 4,413 4,662 (249)
Average crude oil, natural gas and NGLs sales price (per Boe) $ 76.03 $ 57.42 $ 18.61
Average Dated Brent spot price* ($/Bbl) $ 93.15 $ 71.01 $ 22.14
Net crude oil, natural gas, and NGLs revenue $ 344,740 $ 268,230 $ 76,510
Operating costs and expenses:
Production expense 118,827 115,070 3,757
Exploration expense 27,273 2,873 24,400
Depreciation, depletion and amortization 95,838 79,133 16,705
Loss on sale of assets 1,243 - 1,243
General and administrative expense 28,518 26,393 2,125
Credit losses and other 1,312 485 827
Total operating costs and expenses 273,011 223,954 49,057
Operating income 71,729 44,276 27,453
Other expense, net (121,466) (7,594) (113,872)
Income (loss) before income taxes (49,737) 36,682 (86,419)
Income tax expense 41,418 19,470 21,948
Net income (loss) $ (91,155) $ 17,212 $ (108,367)
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.
Crude oil, natural gas and NGLs revenues:
Gabon
Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. Total revenues from our Gabon segment were $187.0 million during the nine months ended September 30, 2026, an increase of $55.0 million from the $132.0 million reported during the nine months ended September 30, 2025. The increase in revenues is primarily due to the higher average realized sales price received in Gabon of $91.96 per Bbl for the nine months ended September 30, 2026 compared to $69.52 per Bbl average realized sales price received during the same period in 2025. Sales volume increased slightly to 1,934 MBbls for the nine months ended September 30, 2026 compared to 1,891 MBbls reported during the same period of 2025. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 226 MBbls and 292 MBbls at September 30, 2026 and 2025, respectively.
Egypt
Crude oil in Egypt is 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, 2026, all crude oil sales were made directly to EGPC. The Company's Egypt segment reported revenue of $127.6 million for the nine months ended September 30, 2026, which is $24.7 million higher
than the $102.9 million of revenue reported during the nine months ended September 30, 2025. The increase in revenues was primarily due to higher average realized sales price, which increased to $61.70 per Bbl for the nine months ended September 30, 2026 from $50.74 per Bbl during the comparable period in 2025, as well as a slight increase in sales volume to 2,068 MBbls for the nine months ended September 30, 2026 compared to 2,027 MBbls during the same period of 2025.
Côte d'Ivoire
Crude oil production from the Côte d'Ivoire assets is marketed under an agreement with an international oil trading company that markets and sells cargoes to purchasers, primarily refineries, worldwide. As previously discussed, the FPSO Baobab Ivoirien ceased production in January 2025 to undergo a planned refurbishment program, which was completed in February 2026. Following completion of the refurbishment, the FPSO Baobab Ivoirien was reconnected to field infrastructure and production resumed from all producing wells. The first crude oil lifting occurred in August 2026. Revenue from the Côte d'Ivoire assets for the nine months ended September 30, 2026 was $27.8 million, reflecting total sales volumes of 328 MBbls at an average realized sales price of $84.94 per Bbl. The Côte d'Ivoire segment reported revenues of $18.4 million during the nine months ended September 30, 2025 with total sales volumes of 238 MBbls and an average realized sales price received of $77.36 per Bbl. Côte d'Ivoire's share of crude oil inventory was approximately 156 MBbls at September 30, 2026.
Canada
Prior to the Canada Assets Divestment, crude oil production from our Canadian operations was typically sold to third parties through pipeline transportation arrangements. During the nine months ended September 30, 2026, revenues from our Canada segment reflected production sold from January 1, 2026 through the closing date of the Canada Assets Divestment. For this period, the Canada segment generated revenues of $2.3 million and reported sales volumes of 83 MBoe, with an average realized sales price of $27.04 per Boe. During the nine months ended September 30, 2025, we recorded revenues of $14.9 million on sales volumes of 506 MBoe and an average realized sales price received of $29.54 per Boe.
Production expenses increased $3.7 million for the nine months ended September 30, 2026 to $118.8 million from $115.1 million for the same period in the prior year. The increase in production expenses was primarily driven by higher chemical costs and fuel costs, partially offset by the change in oil inventory adjustments and decreased expenses as a result of the Canada Assets Divestment. In addition, we incurred non-recurring costs during the same period in the prior year mainly due to government audit settlements. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the nine months ended September 30, 2026 increased to $26.91 per barrel from $24.63 per barrel for the nine months ended September 30, 2025.
Exploration expense for the nine months ended September 30, 2026 of $27.3 million included the costs of additional seismic data for the Niosi and Guduma blocks and the CI-705 block, as well as exploration costs related to drilling activities in Gabon. Exploration expense for the nine months ended September 30, 2025 was $2.9 million, attributable to the purchase of seismic data for Block 705 in Cote d'Ivoire and exploration activities related to the Niosi and Guduma blocks in Gabon.
Depreciation, depletion and amortization costs increased $16.7 million, or approximately 21%, for the nine months ended September 30, 2026 to $95.8 million from $79.1 million during the same period in 2025. The increase in depreciation, depletion and amortization expense is due primarily to the increase in sales volumes and higher depletable costs in Gabon, Egypt and Côte d'Ivoire, partially offset by the Canada Assets Divestment completed in February 2026.
Loss on asset divestment of $1.2 million for the nine months ended September 30, 2026 was attributable to the Canada Assets Divestment, which closed in February 2026.
General and administrative expenses increased $2.1 million, or 8%, for the nine months ended September 30, 2026 to $28.5 million from $26.4 million during the same period in 2025 driven largely by an increase in legal and professional service fees, which included approximately $2.2 million of non-recurring costs associated with business development activities.
Credit losses and other increased by approximately $0.8 million during the nine months ended September 30, 2026 compared to the same period in 2025 primarily due to allowance charges related to receivables from joint venture partners and other receivables.
Commodity derivative instruments loss, net is attributable to our collars, puts and swaps as discussed in Part I, Item 1, Note 7. Derivatives to the unaudited condensed consolidated financial statements. We recorded a $108.9 million net loss on derivative instruments for the nine months ended September 30, 2026, which included an unrealized loss of $46.9 million related to the change in fair value of our commodity derivative contracts primarily driven by an increase in the futures curve for forecasted commodity prices and a realized loss of $61.9 million on matured commodity derivative contracts. We recognized a net loss on derivative instruments of $0.8 million during the same period in 2025. The increase in net derivative loss was primarily attributable to increases in Dated Brent crude oil prices relative to the applicable strike prices of our derivative instruments, as well as increased derivative positions entered into during the current year compared to the prior year. Our derivative instruments currently cover a portion of our crude oil production through December 2027.
Interest expense, net for the nine months ended September 30, 2026 increased to $10.0 million compared to $6.2 million during the same period in 2025. The increase in net interest expense is primarily attributable to increased borrowings under the 2025 RBL Facility and higher amortization of debt issue costs and commitment fees, partially offset by interest income. Interest expense, net also included an unrealized gain of $0.1 million related to changes in the fair value of our interest rate derivative instrument.
Other income (expense), net was an expense of $2.6 million and $0.6 million for the nine months ended September 30, 2026 and 2025, respectively. Other income (expense), net, primarily consists of foreign currency gains and losses.
Income tax expense for the nine months ended September 30, 2026 was $41.4 million, which includes a $6.0 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in kind. Income tax expense for the nine months ended September 30, 2025 was $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.
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