Kvartalsrapport Q4 2025

Report to Shareholders  |  December 31, 2025
PAGE 35
HEALTH & SAFETY RISKS 
The oil and gas industry involves inherent health and safety risks, including harsh and remote environments, heavy equipment, hazardous 
materials, high temperatures and high-pressure equipment. Meren is committed to operating in a safe and responsible manner, in alignment 
with international industry best practice and the laws and regulations of the countries where we operate. The Company maintains a Health & 
Safety policy, which is reviewed annually and outlines its commitments, including the governance processes and management systems used to 
ensure compliance with this policy. Where Meren does not operate, the Company engages with its JV Parties and operators on health and safety 
practices and monitors performance via quarterly reporting.
These efforts can help to reduce but not fully eliminate the risks associated with oil and gas activities, including fire, explosion, blowouts, gas 
releases, ruptures and personnel accidents. Should they occur, each of these hazards could result in substantial personal injury to employees, 
contractors or other bystanders, as well as damage to oil and gas wells, production facilities and other property. In this case, the Company could 
be exposed to fines, penalties and other legal liabilities, as well as reputational damage, including loss of license to operate, and such damages 
may not be fully insurable.
CLIMATE RISKS 
Market Risks
Changing consumer preferences for low carbon sources of energy, transport and products and services may erode demand for oil and gas as 
alternatives come to market and gain scale. Although recent political developments in the United States and a recalibration of climate priorities 
in parts of the European Union have contributed to a more fragmented global policy landscape, market forces, capital allocation trends, and 
technological developments continue to drive the adoption of lower carbon solutions. As a result, reduced demand for oil and gas may result in 
stranded reserves or resources and negatively impact the Company’s valuation and share price. In addition to limiting the Company’s ability to 
sell into the market, these trends could lead to lower commodity prices in the medium and long-term, putting further pressure on revenues. In 
the short-term, unbalanced investment in traditional vs. new energy technologies and sources, combined with uncertain demand dynamics, may 
lead to commodity price volatility. Supply chains may also become constrained, as suppliers adjust their strategies and product mix in response 
to the energy transition, resulting in increasing costs for some goods and services. 
The Company has conducted scenario analysis, which suggests the current portfolio remains competitive in a low demand environment. We 
update our analysis on a regular basis and ahead of new project sanction to minimize the risk of stranded assets. In order to remain resilient 
in an uncertain and volatile future commodity environment, the Company works with and through its parties to reduce operational costs as 
much as possible without sacrificing health and safety or longer-term efficiency and environmental or strategic goals. Additionally, the Company 
will maintain a prudent budget and financial strategy, including hedging as appropriate, to manage medium term oil price volatility ensure the 
business remains resilient in a low oil price scenarios. 
Litigation Risks 
Climate-related litigation is a rapidly evolving and increasingly important issue for our industry. The risk of legal challenges could rise as the 
costs of climate change mitigation and adaptation increase, and as more climate laws and agreements are put in place. Climate-related litigation 
could result in liabilities or loss of license related to current or historical activities’ contribution to global emissions. We do not consider Meren 
at immediate risk of climate litigation but are monitoring developments closely. Even if the Company is not directly targeted by litigation, 
operations may be indirectly impacted by outcomes in related cases involving other oil and gas companies in jurisdictions where we operate. The 
Company will seek legal counsel as required to remain abreast of potential legal action and its implications for our business.
Regulatory Risks 
Since the Paris Agreement was signed in 2015, countries have steadily enacted policies to enable the transition to a low carbon future and 
meet their Nationally Determined Contributions (NDCs). This includes the governments of countries where Meren conducts business. These 
policies may directly or indirectly increase the cost of doing business in these countries or potentially restrict the Company’s ability to operate.  
Meren regularly monitors the evolving regulatory landscape, both globally and in the Company’s countries of operation, to anticipate the 
impact of new climate-related measures and ensure the Company remains compliant. Additionally, the Company is developing a comprehensive 
energy transition strategy, including measures to minimize operational emissions in line with Paris Agreement objectives, which should help the 
Company to remain aligned with evolving regulatory requirements and minimize negative impacts.
Reputational Risk 
Increased scrutiny, pressure and action by environmental activists, non-governmental organizations and other stakeholders may result in 
disruption to operations or loss of license to operate. Such disruption may negatively impact cash flows, returns or the value of our portfolio. 
Similarly, companies within the sector and our supply chain may make emissions performance and climate risk management explicit in partner 
or contract decisions. The Company has not been directly targeted by environmental activists but could be targeted in the future. To mitigate 
this risk, Meren proactively engages with the communities and other stakeholders where the Company operates to keep them informed about 
the impact of our operations on the environment and their livelihoods. The Company also ensures proper security is in place to minimize the 
impact of any potential disruptions and prevent harm to staff, bystanders and assets. 
In addition to environmental activists, numerous banks and large institutional investors have communicated an intention to divest from or limit 
future exposure to fossil fuels, including oil and gas.  Increasing investor and lender concerns regarding climate resilience could limit access 
to capital, increase the cost of that capital via higher interest rates or result in direct costs associated with new measures to meet investor 
expectations. Since 2020, Meren has published public climate disclosures aligned with the Taskforce for Climate-Related Financial Disclosures 
(TCFD) recommendations to proactively address investor and other stakeholder concerns regarding climate risk exposure. In addition, Meren 
regularly engages with investors and lenders to understand their climate policies and requirements and to inform them about the steps the 
Company is taking to manage climate risks. This includes development of a strategy to minimize operational emissions.
RISK FACTORS - CONTINUED

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Report to Shareholders  |  December 31, 2025
PAGE 36
Physical Risks 
Climate change has already resulted in significant shifts in global weather patterns, including an increase in the number and severity of heat 
waves, cold spells, droughts and storms, including hurricanes and tropical cyclones. Longer term, climate change may also result in rising sea 
levels due to melting polar ice caps. The physical effects of climate change have the potential to directly impact the Company’s assets and 
operations. In 2022, the Company contracted a global climate risk analytics company to perform a quantified assessment of the physical 
climate risks facing the Company’s assets under three IPCC climate scenarios: SSP1-2.6 (consistent with 1.8°C warming), SSP2-4.5 (consistent 
with 2.7°C warming) and SSP5-8.5 (consistent with 4.4°C warming). That analysis suggests exposure to future changes in physical climate 
hazards is relatively minimal compared to the historical baseline across all three scenarios. We will continue to monitor our assets’ exposure to 
physical climate risks as our portfolio and the global scientific community’s understanding of changing climate patterns evolves.
Other Environmental Risks
The regulatory frameworks in the Company’s countries of operation extend beyond emissions to include broader areas of environmental concern, 
including water management, waste handling, soil pollution and biodiversity protection. These regulations typically include environmental 
licensing and permitting subject to the conduct of Environmental and Social Impact Assessments prior to any new exploration or development 
activity, as well as ongoing monitoring and reporting. 
Non-compliance with environmental regulations can result in fines or permits being revoked, both of which could materially impact the 
Company’s financial position or license to operate. Breaches could also lead to civil or criminal litigation, particularly in cases resulting in 
significant environmental damage. 
The Company is committed to minimizing the broader environmental impact of its activities. The Company acts in compliance with the applicable 
environmental laws and regulations of its countries of operation and manages activities according to good international practice. This includes 
taking a rigorous approach to operational planning, including identifying potential environmental or social risks and impacts of operations, and 
obtaining and maintaining all necessary permits and licenses. The Company also consults with stakeholders on environmental issues that may 
affect them, investigates any environmental incidents, and maintains emergency response procedures for protection of the environment. 
The Company assesses and puts measures in place to minimize impact on biodiversity and ecosystem services in line with the mitigation 
hierarchy to ensure that activities lead to no net loss of natural habitats. Where the Company is not the operator, it monitors environmental 
risk management via regular reports from JV parties and operators and participation in quarterly operating and technical committee meetings. 
Though the Company endeavors to engage all relevant stakeholders proactively and early in the project planning process, environmental 
activism is increasing, and in some cases has resulted in delays or disruptions to activities, including delays to permitting where activists have 
challenged permits in courts. Meren has not to date suffered impacts to operations due to environmental activism. However, such delays could 
affect project economics by incurring additional costs or delaying forecast production and revenues.
The Company does not currently face any environmental fines or charges. However, accidents can occur and the unexpected nature of these 
events makes the timing and scope challenging to quantify with respect to financial impacts. 
Insurance 
The Company's involvement in oil and gas operations may result in the Company becoming subject to liability for pollution, blow-outs, property 
damage, personal injury or other hazards. While the Company obtains insurance in accordance with industry standards to address such risks, 
the nature of the risks facing the oil and gas industry is such that liabilities might exceed policy limits, the liabilities and hazards might not be 
insurable, or the Company might elect not to insure itself against such liabilities due to high premium costs or other reasons. The payment of 
such uninsured liabilities would reduce the funds available to the Company.  The occurrence of a significant event that the Company is not fully 
insured against, or the insolvency of an insurer, could have a material adverse effect on the Company’s business, financial condition and results 
of operations. There can be no assurance that insurance will be available in the future.  
INVESTMENTS IN ASSOCIATES AND INVESTMENTS IN JOINT VENTURES
The Company has invested in other frontier oil and gas exploration companies that face similar risks and uncertainties, which could have a 
material adverse effect on their businesses, prospects and results of operations. Such risks include, without limitation, equity risk, liquidity risk, 
commodity price risk, credit risk, currency risk, foreign investment risk, and changes in environmental regulations, economic, political or market 
conditions, or the regulatory environment in the countries in which they operate. The associates or joint ventures are entities in which the 
Company has some influence, including through its representation on their boards, but given its equal or minority interest, no or limited control 
over their decisions, including, without limitation, financial and operational policies, the Company has no or limited control over outcomes, 
performance and governance. The Company’s access to information is subject to the contractual provisions of shareholder agreements. The 
Company is reliant on the information provided by investments and may not have the ability to independently verify such information. The 
Company’s investments are not diversified over different types of investments and industries, rather, they are concentrated in one type of 
investment. If an associated company or jointly controlled entity in which the Company has invested fails, liquidates, or becomes bankrupt, the 
Company could face the potential risk of loss of some, or all, of its investments, and may be unable to recover any of its investments. 
The Company’s share price performance is subject to timely communication of financial and operational results. The Company is reliant on 
its associates and joint ventures for timely and accurate disclosures of material updates. Although the Company has procedures in place to 
maximise its oversight of such disclosures, including representation on the boards of its investee companies, failure to mitigate delays and/or 
inaccuracies in such disclosures could expose the Company to regulatory sanctions and shareholder legal action that could adversely impact 
the Company’s finances and reputation.
RISK FACTORS - CONTINUED

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Report to Shareholders  |  December 31, 2025
PAGE 37
LEGAL SYSTEM, LITIGATION AND REMEDIES 
Meren’s production, exploration, development and production activities are located in countries with legal systems that in various degrees differ 
from that of Canada. Rules, regulations and legal principles may differ in respect of matters of substantive law and of such matters as court 
procedure and enforcement. Almost all material exploration and production rights and related contracts of the Company are subject to the 
national or local laws and jurisdiction of the respective countries in which the operations are carried out. This means that the Company’s ability 
to exercise or enforce its rights and obligations may differ between different countries and also from what would have been the case if such 
rights and obligations were subject to Canadian law and jurisdiction. 
Meren’s operations are, to a large extent, subject to various complex laws and regulations as well as detailed provisions in concessions, licenses 
and agreements that often involve several parties. If the Company was to become involved in legal disputes in order to defend or enforce any of 
its rights or obligations under such concessions, licenses, and agreements or otherwise, such disputes or related litigation could be costly, time 
consuming and the outcome would be highly uncertain. Even if the Company ultimately prevailed, such disputes and litigation may still have a 
substantially negative effect on the Company’s business, assets, financial conditions, and its operations. 
Securities legislation in certain of the provinces and territories of Canada provides purchasers with various rights and remedies when a reporting 
issuer’s continuous disclosure contains a misrepresentation and ongoing rights to bring actions for civil liability for secondary market disclosure. 
Under the legislation, the directors would be liable for a misrepresentation. It may be difficult for investors to collect from the directors who are 
resident outside Canada on judgements obtained in courts in Canada predicated on the purchaser’s statutory rights and on other civil liability 
provisions of Canadian securities legislation.
BRIBERY, CORRUPTION AND FRAUD 
The Company is subject to various laws which aim to combat bribery, corruption and fraud, including the Corruption of Foreign Public Officials 
Act (Canada) and the Bribery Act 2010 (United Kingdom) and the Economic Crime and Corporate Transparency Act 2023 (United Kingdom). 
Failure to comply with such laws could subject the Company to, among other things, civil and criminal penalties, other remedial measures and 
legal expenses and reputational damage, each of which could adversely affect the Company’s business, results in operations, and financial 
condition. Weaknesses in the anti-corruption legal and judicial system of certain countries may undermine the Company’s or a host government’s 
capacity to effectively detect, prevent and sanction corruption and fraud. To mitigate this risk, the Company has implemented an anti-corruption 
compliance and onboarding program for anyone that does business with the Company, anti-corruption training initiatives for its personnel 
and consultants, and an anti-corruption policy for its personnel, and consultants. However, the Company cannot guarantee that its personnel, 
contractors, or business partners have not in the past or will not in the future engage in conduct undetected by the onboarding processes and 
procedures adopted by the Company, and it is possible that the Company, its personnel or contractors, could be subject to investigations or 
charges related to bribery, corruption or fraud as a result of actions of its personnel or contractors. 
SIGNIFICANT SHAREHOLDER
BTG Oil & Gas, an investment company which is a subsidiary of BTG Pactual, the largest investment bank in Latin America based in São Paulo, 
Brazil, owns approximately 35.5 percent of the aggregate common shares of the Company. BTG Oil & Gas’s holdings may allow it to significantly 
affect substantially all the actions taken by the shareholders of the Company, including the election of directors. As long as BTG Oil & Gas 
maintains a significant interest in the Company, it is likely that BTG Oil & Gas will exercise significant influence on the ability of the Company to, 
among other things, enter into a change in control transaction of the Company and may also discourage acquisition bids for the Company. There 
is a risk that the interests of BTG Oil & Gas may not be aligned with the interests of other shareholders.
RISK FACTORS - CONTINUED

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Report to Shareholders  |  December 31, 2025
PAGE 38
FORWARD-LOOKING STATEMENTS
Certain statements in this document may constitute forward-looking information or forward-looking statements under applicable Canadian 
securities law (collectively “forward-looking statements”). Forward-looking statements are statements that relate to future events, including 
the Company’s future performance, opportunities or business prospects. All statements other than statements of historical fact may be 
forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute 
forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically 
exploited. Any statements that express or involve discussions with respect to expectations, forecasts, assumptions, objectives, beliefs, 
projections, plans, guidance, predictions, future events or performance (often, but not always, identified by words such as “believes”, “seeks”, 
“anticipates”, “expects”, “continues”, “may”, “projects”, “estimates”, “forecasts”, “pending”, “intends”, “plans”, “could”, “might”, “should”, “will”, “would 
have” or similar words suggesting future outcomes) are not statements of historical fact and may be forward-looking statements. 
By their nature, forward-looking statements involve assumptions, inherent risks and uncertainties, many of which are difficult to predict, and 
are usually beyond the control of management, that could cause actual results to be materially different from those expressed by these 
forward-looking statements. Undue reliance should not be placed on these forward-looking statements because the Company cannot assure 
that the forward-looking statements will prove to be correct. As forward-looking information addresses future conditions and events, it could 
involve risks and uncertainties including, but not limited to, risk with respect to macro-economic conditions and their impact on operations, 
regulations and taxes, civil unrest, corporate restructuring and related costs, capital and operating expenses, pricing and availability of financing 
and currency exchange rate fluctuations. Readers are cautioned that the assumptions used in the preparation of such information, although 
considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-
looking statements. 
Forward-looking statements include, but are not limited to, statements concerning: 
 ● A change to the shareholder capital return program including the continuation of the based dividend policy, distribution of special dividends 
and/or the implementation of share buy-backs;
 ● Planned exploration, appraisal and development activity including both expected drilling, and geological and geophysical related activities;
 ● Proposed development plans;
 ● Future development costs and the funding thereof;
 ● Expected funding and development costs;
 ● Anticipated future financing requirements;
 ● Future sources of funding for the Company’s capital program;
 ● Future capital expenditures and their allocation to exploration and development activities;
 ● Expected operating costs;
 ● Future sources of liquidity, ability to fully fund the Company’s expenditures from cash flows, and borrowing capacity;
 ● Availability of potential farmout partners/ parties;
 ● The Company’s ability to successfully identify, complete and integrate potential acquisition opportunities;
 ● Government or other regulatory consent for exploration, development, farmout, or acquisition activities;
 ● Future production levels;
 ● Future crude oil or natural gas prices;
 ● Future earnings;
 ● The Company’s ability to deliver further growth and expectations regarding free-cash flow;
 ● Future asset acquisitions or dispositions and the anticipated strategic and financial benefits of those transactions;
 ● Future debt levels;
 ● Availability of committed credit facilities, including existing credit facilities, on terms and timing acceptable to the Company;
 ● Possible commerciality;
 ● Development plans or capacity expansions;
 ● Future ability to execute dispositions of assets or businesses;
 ● Future drilling of new wells;
 ● Ultimate recoverability of current and long-term assets;
 ● Ultimate recoverability of reserves or resources;
 ● The sustainability of the Company across oil and gas price cycles;
 ● Future foreign currency exchange rates;
 ● Future market interest rates;
 ● Future expenditures and future allowances relating to environmental matters;
 ● The Company’s plans and targets to reduce the Company’s net emissions;
 ● Dates by which certain areas will be explored or developed or will come on stream or reach expected operating capacity; 
 ● The Company’s ability to comply with future legislation or regulations;
 ● Future staffing level requirements; and
 ● Changes to any of the foregoing.

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Report to Shareholders  |  December 31, 2025
PAGE 39
FORWARD-LOOKING STATEMENTS - CONTINUED
Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates 
and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in 
the future.
These forward-looking statements are subject to known and unknown risks and uncertainties and other factors, which may cause actual results, 
levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others:
 ● Market prices for oil and gas;
 ● Uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses;
 ● Changes in exploration or development project plans or capital expenditures;  
 ● The Company’s ability to explore, develop, produce and transport crude oil and natural gas to markets;
 ● Production and development costs and capital expenditures;
 ● The imprecise nature of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; 
 ● Availability of financing;
 ● Uninsured risks;
 ● Changes in interest rates and foreign-currency exchange rates;
 ● Regulatory changes;
 ● Changes in the political or social climate in the regions in which the Company operates;
 ● Health, safety and environmental risks;
 ● Climate change legislation and regulation changes;
 ● Defects in title;
 ● Availability of materials and equipment;
 ● Timelines of government or other regulatory approvals;
 ● Ultimate effectiveness of design or design modification to facilities;
 ● The results of exploration, appraisal and development drilling and related activities;
 ● Short-term well test results on exploration and appraisal wells do not necessarily indicate the long-term performance or ultimate recovery 
that may be expected from a well;
 ● Pipeline or delivery constraints;
 ● Volatility in energy trading markets;
 ● Incorrect assessments of value when making acquisitions;
 ● Economic conditions in the countries and regions in which the Company carries on business;
 ● Governmental actions including changes to taxes or royalties, the imposition of tariffs or changes in environmental or other laws and 
regulations;
 ● The Company’s treatment under governmental regulatory regimes and tax laws;
 ● Renegotiations of contracts;
 ● Results of litigation, arbitration or regulatory proceedings;
 ● Political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict;
 ● Internal conflicts within states or regions;
 ● Dates by which certain areas will be explored or developed or will come onstream or reach expected operating capacity;
 ● The Company’s ability to comply with future legislation or regulations;
 ● Future staffing level requirements; and 
 ● Changes to any of the foregoing.
The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors 
are interdependent, and management’s future course of action would depend on its assessment of all available information at that time. 
Although management believes that the expectations conveyed by the forward-looking statements are reasonable based on the information 
available to it on the date such forward-looking statements were made, no assurances can be given that such expectations will prove to be 
correct, and such forward-looking statements included in, or incorporated by reference into, this document should not be unduly relied upon.
The forward-looking statements are made as of the date hereof or as of the date specified in the documents incorporated by reference into this 
document, as the case may be, and except as required by law, the Company undertakes no obligation to update publicly, re-issue, or revise any 
forward-looking statements, whether as a result of new information, future events or otherwise. This cautionary statement expressly qualifies 
the forward-looking statements contained herein.

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PAGE 40
Report to Shareholders  |  December 31, 2025
 
PricewaterhouseCoopers LLP 
Suncor Energy Centre, 111 5th Avenue South West, Suite 2900 
Calgary, Alberta, Canada  T2P 5L3 
T.: +1 403 509 7500, F.: +1 403 781 1825 
Fax to mail: ca_calgary_main_fax@pwc.com 
“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership. 
Independent auditor’s report 
To the Shareholders of Meren Energy Inc. (previously called Africa Oil Corp.) 
Our opinion 
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, 
the financial position of Meren Energy Inc. (previously called Africa Oil Corp.) and its subsidiaries (together, 
the Company) as at December 31, 2025 and 2024, and its financial performance and its cash flows for the 
years then ended in accordance with International Financial Reporting Standards as issued by the 
International Accounting Standards Board (IFRS Accounting Standards). 
What we have audited 
The Company’s consolidated financial statements comprise: 
• the consolidated balance sheets as at December 31, 2025 and 2024; 
• the consolidated statements of net income or loss and other comprehensive income or loss for the years 
then ended; 
• the consolidated statements of equity for the years then ended; 
• the consolidated statements of cash flows for the years then ended; and 
• the notes to the consolidated financial statements, comprising material accounting policy information and 
other explanatory information.

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PAGE 41
Report to Shareholders  |  December 31, 2025
 
Basis for opinion 
We conducted our audit in accordance with Canadian generally accepted auditing standards. Our 
responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of 
the consolidated financial statements section of our report. 
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our 
opinion. 
Independence 
We are independent of the Company in accordance with the ethical requirements that are relevant to our 
audit of the consolidated financial statements in Canada. We have fulfilled our other ethical responsibilities 
in accordance with these requirements. 
Key audit matters 
Key audit matters are those matters that, in our professional judgment, were of most significance in our 
audit of the consolidated financial statements for the year ended December 31, 2025. These matters were 
addressed in the context of our audit of the consolidated financial statements as a whole, and in forming our 
opinion thereon, and we do not provide a separate opinion on these matters. 
Key audit matter How our audit addressed the key audit matter 
Valuation of oil and gas properties acquired in the 
Meren Coop business acquisition  
Refer to note 2 – Basis of preparation, note 3 – Material 
accounting policies, and note 4 – Business combination to the 
consolidated financial statements.  
On March 19, 2025, the Company completed the transaction 
with BTG Oil & Gas to consolidate its interest in Meren 
Coöperatief U.A (previously known as Prime Oil and Gas 
Coöperatief U.A) (Meren Coop). The acquisition was completed 
by way of amalgamation whereby BTG Oil & Gas exchanged its 
50 percent interest in Meren Coop, held through its fully owned 
subsidiary BTG Pactual Holding S.à.r.l., in exchange for 
Our approach to addressing the matter included the following 
procedures, among others:  
 The work of management’s experts was used in 
performing the procedures to evaluate the reasonableness 
of the acquired proved and probable oil and gas reserves 
used to determine the fair value of the oil and gas 
properties acquired. As a basis for using this work, the 
competence, capabilities and objectivity of management’s 
experts were evaluated, the work performed was 
understood and the appropriateness of the work as audit

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PAGE 42
Report to Shareholders  |  December 31, 2025
 
Key audit matter How our audit addressed the key audit matter 
239,828,655 newly issued shares in the Company. 
Management has regarded the acquisition as a business 
combination and has accounted for it using the acquisition 
method of accounting in accordance with IFRS 3. Management 
performed a final purchase price allocation (PPA) to allocate the 
consideration to the fair value of assets acquired and liabilities 
assumed. The fair value of oil and gas properties acquired was 
$1,538.1million.  
Management determined the fair value for oil and gas 
properties as the present value of estimated future cash flows 
arising from the continued use of the assets. Fair value for oil 
and gas properties is determined using a discounted cash flow 
model. The significant assumptions developed by management 
used to determine the fair value of the oil and gas properties 
acquired in the Meren Coop business acquisition include the 
quantity of proved and probable oil and gas reserves, future 
commodity prices, operating and capital costs and discount 
rates. The proved and probable oil and gas reserves are 
prepared by the Company’s independent petroleum engineers 
(management’s experts).  
We considered this a key audit matter due to (i) the significant 
judgment applied by management, including the use of 
management’s experts, when determining the fair value of the 
oil and gas properties acquired in the Meren Coop business 
acquisition, including the development of the significant 
assumptions; (ii) a high degree of auditor judgment, subjectivity 
and effort in performing procedures and evaluating audit 
evidence relating to the significant assumptions used by 
management; and (iii) the audit effort involved the use of 
professionals with specialized skill and knowledge in the field of 
valuation and in the field of petroleum engineering and reserves 
estimation. 
evidence was evaluated. The procedures performed also 
included evaluation of the methods and assumptions used 
by management’s experts, and an evaluation of their 
findings. Professionals with specialized skill and 
knowledge in the field of petroleum engineering and 
reserves estimation assisted in this evaluation. 
 Tested how management determined the fair value of the 
oil and gas properties acquired, which included the 
following:  
 Read the purchase agreement. 
 Evaluated the appropriateness of management’s 
discounted cashflow model and tested the 
mathematical accuracy thereof.  
 Tested the underlying data used by management in 
the discounted cash flow model.  
 Evaluated the reasonableness of the significant 
assumptions used by management in developing the 
underlying estimates, including: 
o quantity of proved and probable oil and gas 
reserves, operating and capital costs by 
considering the past performance of the oil and 
gas properties acquired, and whether these 
assumptions were consistent with evidence 
obtained in other areas of the audit;  
o future commodity prices by comparing those 
prices with other reputable third-party industry 
sourced commodity prices; and  
o the discount rate, through the assistance of 
professionals with specialized skill and 
knowledge in the field of valuation.

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PAGE 43
Report to Shareholders  |  December 31, 2025
 
Key audit matter How our audit addressed the key audit matter 
Impact of oil and gas reserves on oil and gas 
properties for the Agbami field cash generating unit 
(CGU) 
Refer to note 2 – Basis of preparation, note 3 – Material 
accounting policies, and note 5 – Oil and gas properties to the 
consolidated financial statements. 
The Company had $1,413.5 million of net oil and gas properties 
as at December 31, 2025. Depletion expense was 
$207.9  million for the year then ended. Oil and gas properties 
are depleted using the Unit of Production (UoP) method over 
total estimated proved and probable oil and gas reserves.  
Oil and gas properties are grouped for recoverability 
assessment purposes into cash generating units (CGUs). At 
each reporting period, management assesses its CGUs to 
determine whether any indication of impairment exists. Where 
an indicator of impairment exists, with reference to total proved 
and probable oil and gas reserves, a formal estimate of the 
recoverable amount is made, which is considered to be the 
higher of the fair value less costs to dispose and value in use. 
An impairment loss is recognized if the carrying amount of the 
CGU exceeds its estimated recoverable amount. 
As at December 31, 2025, management determined there was 
an indicator of impairment in relation to the Agbami field CGU 
as a result of a combination of increased costs and lower oil 
prices.   
Management calculated the recoverable amount of the Agbami 
field CGU using a fair value less costs to dispose cashflow 
model, which is based on the discounted future after tax net 
cash flows of proved and probable oil and gas reserves. The 
proved and probable oil and gas reserves are prepared by 
management’s experts. 
The significant assumptions used by management to determine 
the recoverable amount of the Agbami field CGU include the 
quantity of proved and probable oil and gas reserves, future 
Our approach to addressing the matter included the following 
procedures, among others: 
 The work of management’s experts was used in 
performing the procedures to evaluate the reasonableness 
of the proved and probable oil and gas reserves used to 
determine the depletion expense and the recoverable 
amount of oil and gas properties in the Agbami field CGU. 
As a basis for using this work, the competence, 
capabilities and objectivity of management’s experts was 
evaluated, the work performed was understood and the 
appropriateness of the work as audit evidence was 
evaluated. The procedures performed also included 
evaluation of the methods and assumptions used by 
management’s experts, tests of the data used by 
management’s experts and an evaluation of their findings. 
Professionals with specialized skill and knowledge in the 
field of petroleum engineering and reserves estimation 
assisted in this evaluation. 
 Tested how management determined the recoverable 
amount of the Agbami field CGU and depletion expense, 
which included the following:  
 Evaluated the appropriateness of the methods used 
by management in making these estimates. 
 Tested the data used in determining these estimates. 
 Evaluated the reasonableness of significant 
assumptions used by management in developing the 
underlying estimates, including: 
o quantity of proved and probable oil and gas 
reserves, operating and capital costs by 
considering the past performance of the 
Agbami field CGU, and whether these 
assumptions were consistent with evidence 
obtained in other areas of the audit;

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PAGE 44
Report to Shareholders  |  December 31, 2025
 
Key audit matter How our audit addressed the key audit matter 
commodity prices, operating and capital costs and discount 
rates. 
During the year ended December 31, 2025, management 
recorded an impairment charge of $105.3 million on the oil and 
gas properties related to the Agbami field CGU. 
We considered this a key audit matter due to (i) the significant 
judgment by management, including the use of management’s 
experts, when developing the expected future cash flows to 
determine the recoverable amount and the proved and probable 
oil and gas reserves; (ii) a high degree of auditor judgment, 
subjectivity and effort in performing procedures relating to the 
significant assumptions; and (iii) the audit effort involved the 
use of professionals with specialized skill and knowledge in the 
field of valuation and petroleum engineering and reserves 
estimation. 
o future commodity prices by comparing those 
prices with other reputable third party 
industry sourced commodity prices; and 
o the discount rate, through the assistance of 
professionals with specialized skill and 
knowledge in the field of valuation. 
 Recalculated the UoP rates used to calculate depletion 
expense for the Agbami field CGU. 
Other information 
Management is responsible for the other information. The other information comprises the Management's 
Discussion and Analysis, which we obtained prior to the date of this auditor’s report and the information, 
other than the consolidated financial statements and our auditor’s report thereon, included in the Report to 
Shareholders, which is expected to be made available to us after that date. 
Our opinion on the consolidated financial statements does not cover the other information and we do not 
and will not express any form of assurance conclusion thereon. 
In connection with our audit of the consolidated financial statements, our responsibility is to read the other 
information identified above and, in doing so, consider whether the other information is materially 
inconsistent with the consolidated financial statements or our knowledge obtained in the audit, or otherwise 
appears to be materially misstated.

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PAGE 45
Report to Shareholders  |  December 31, 2025
 
If, based on the work we have performed on the other information that we obtained prior to the date of this 
auditor’s report, we conclude that there is a material misstatement of this other information, we are required 
to report that fact. We have nothing to report in this regard. When we read the information, other than the 
consolidated financial statements and our auditor’s report thereon, included in the Report to Shareholders, 
if we conclude that there is a material misstatement therein, we are required to communicate the matter to 
those charged with governance. 
Responsibilities of management and those charged with governance for the 
consolidated financial statements 
Management is responsible for the preparation and fair presentation of the consolidated financial 
statements in accordance with IFRS Accounting Standards, and for such internal control as management 
determines is necessary to enable the preparation of consolidated financial statements that are free from 
material misstatement, whether due to fraud or error. 
In preparing the consolidated financial statements, management is responsible for assessing the Company’s 
ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using 
the going concern basis of accounting unless management either intends to liquidate the Company or to 
cease operations, or has no realistic alternative but to do so. 
Those charged with governance are responsible for overseeing the Company’s financial reporting process. 
Auditor’s responsibilities for the audit of the consolidated financial statements 
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a 
whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report 
that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an 
audit conducted in accordance with Canadian generally accepted auditing standards will always detect a 
material misstatement when it exists. Misstatements can arise from fraud or error and are considered 
material if, individually or in the aggregate, they could reasonably be expected to influence the economic 
decisions of users taken on the basis of these consolidated financial statements.

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PAGE 46
Report to Shareholders  |  December 31, 2025
 
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise 
professional judgment and maintain professional skepticism throughout the audit. We also: 
• Identify and assess the risks of material misstatement of the consolidated financial statements, whether 
due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit 
evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a 
material misstatement resulting from fraud is higher than for one resulting from error, as fraud may 
involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. 
• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that 
are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness 
of the Company’s internal control. 
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates 
and related disclosures made by management. 
• Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based 
on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that 
may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a 
material uncertainty exists, we are required to draw attention in our auditor’s report to the related 
disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our 
opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. 
However, future events or conditions may cause the Company to cease to continue as a going concern. 
• Evaluate the overall presentation, structure and content of the consolidated financial statements, 
including the disclosures, and whether the consolidated financial statements represent the underlying 
transactions and events in a manner that achieves fair presentation. 
• Plan and perform the group audit to obtain sufficient appropriate audit evidence regarding the financial 
information of the entities or business units within the Company as a basis for forming an opinion on the 
consolidated financial statements. We are responsible for the direction, supervision and review of the 
audit work performed for purposes of the group audit. We remain solely responsible for our audit opinion. 
We communicate with those charged with governance regarding, among other matters, the planned scope 
and timing of the audit and significant audit findings, including any significant deficiencies in internal 
control that we identify during our audit.

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PAGE 47
Report to Shareholders  |  December 31, 2025
 
We also provide those charged with governance with a statement that we have complied with relevant ethical 
requirements regarding independence, and to communicate with them all relationships and other matters 
that may reasonably be thought to bear on our independence, and where applicable, related safeguards. 
From the matters communicated with those charged with governance, we determine those matters that were 
of most significance in the audit of the consolidated financial statements of the current period and are 
therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation 
precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a 
matter should not be communicated in our report because the adverse consequences of doing so would 
reasonably be expected to outweigh the public interest benefits of such communication. 
The engagement partner on the audit resulting in this independent auditor’s report is Khurram Asghar. 
/s/PricewaterhouseCoopers LLP 
Chartered Professional Accountants 
Calgary, Alberta, Canada 
February 24, 2026

===== SIDA 57 =====

PAGE 48
Report to Shareholders  |  December 31, 2025
(Expressed in millions of United States dollars)
CONSOLIDATED BALANCE SHEET
 As at   Note
December 31, 
2025
December 31, 
2024
ASSETS
Non-current assets
Oil and gas properties 5 1,413.5 -
Intangible exploration assets 6 43.7 29.3
Other tangible fixed assets 3.7 3.2
Equity investment in joint venture 7 - 328.4
Equity investments in associates 8 142.2 177.6
1,603.1 538.5
Current assets
Inventories 9 94.2 -
Investment held for sale 10 - 7.0
Loan to associated company 26 - 4.3
Trade and other receivables 11 77.7 4.0
Derivative financial instruments 29 2.2 -
Cash and cash equivalents 12 174.7 61.4
348.8 76.7
Total assets 1,951.9 615.2
LIABILITIES AND EQUITY
Equity attributable to common shareholders
Share capital 13 1,536.2 1,195.8
Contributed surplus 95.5 87.4
Treasury share account - (0.4)
Deficit (865.8) (734.0)
Total equity attributable to common shareholders 765.9 548.8
Non-current liabilities
Financial liabilities 15 265.2 2.6
Provisions 14 271.3 49.2
Deferred tax liabilities 24 281.8 -
818.3 51.8
Current liabilities
Financial liabilities 15 68.6 0.7
Trade and other payables 16 150.8 9.7
Current tax liabilities 24 48.5 -
Provisions 14 99.8 4.2
367.7 14.6
Total liabilities 1,186.0 66.4
Total liabilities and equity attributable to common shareholders 1,951.9 615.2
The notes are an integral part of the consolidated financial statements. 
Approved on behalf of the Board:
“MICHAEL EBSARY” “OLIVER QUINN”
MICHAEL EBSARY, DIRECTOR OLIVER QUINN, DIRECTOR

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PAGE 49
Report to Shareholders  |  December 31, 2025
(Expressed in millions of United States dollars)
CONSOLIDATED STATEMENT OF NET INCOME 
OR LOSS AND OTHER COMPREHENSIVE 
INCOME OR LOSS
For the years ended Note
December 31, 
2025
December 31, 
2024
Oil and gas sales 19 559.9 -
Net revenue 559.9 -
Commodity risk management contracts 29 2.2 -
Revenue 562.1 -
Cost of Sales
Movements on overlift/underlift balances (46.3) -
Production costs 20 (166.6) -
Depletion costs 5 (207.9) -
Impairment charges 5 (105.3) -
(526.1) -
Gross profit 36.0 -
General and administrative expenses (36.4) (32.4)
Operating loss (0.4) (32.4)
Finance income 22 4.1 7.6
Finance expense 23 (47.8) (4.9)
Net financial items (43.7) 2.7
Share of profit from investment in joint venture 7 2.9 226.0
Share of loss from investments in associates 8 (2.9) (38.7)
Reversal of impairment/ (impairment) of investment in joint venture 7 55.9 (436.7)
Income/ (loss) before tax 11.8 (279.1)
Income tax 24 (43.4) -
Net loss attributable to common shareholders (31.6) (279.1)
Total comprehensive loss (31.6) (279.1)
Net loss attributable to common shareholders per share
Basic 25 (0.05) (0.62)
Diluted 25 (0.05) (0.62)
Weighted average number of shares outstanding for the purpose of 
calculating earnings per share
Basic 25 624,464,015 449,431,803
Diluted 25 624,464,015 449,431,803
The notes are an integral part of the consolidated financial statements.

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PAGE 50
Report to Shareholders  |  December 31, 2025
(Expressed in millions of United States dollars)
CONSOLIDATED STATEMENT OF EQUITY
For the years ended Note
December 31, 
2025
December 31, 
2024
Share capital: 13(A)
Balance, beginning of the year 1,195.8 1,265.3
Share issuance to BTG Oil & Gas under Amalgamation Agreement 13 353.2 -
Exercise of Share Options 13 0.4 0.5
Settlement of Restricted Share Units 13 1.1 0.5
Settlement of Performance Share Units 13 2.5 1.1
Weighted average value of shares cancelled 13 (16.8) (71.6)
Balance, end of the year 1,536.2 1,195.8
Contributed surplus: 
Balance, beginning of the year 87.4 61.6
Excess of weighted value of shares cancelled 13 8.1 25.8
Balance, end of the year 95.5 87.4
Treasury account: 
Balance, beginning of the year (0.4) -
Shares purchased 13 (8.3) (46.2)
Shares cancelled 13 8.7 45.8
Balance, end of the year - (0.4)
Deficit:
Balance, beginning of the year (734.0) (432.3)
Dividends 13 (100.2) (22.6)
Net income attributable to common shareholders (31.6) (279.1)
Balance, end of the year (865.8) (734.0)
Total equity attributable to common shareholders
Balance, end of the year 765.9 548.8
The notes are an integral part of the consolidated financial statements.

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PAGE 51
Report to Shareholders  |  December 31, 2025
CONSOLIDATED STATEMENT  
OF CASH FLOWS
(Expressed in millions of United States dollars)
For the years ended Note
December 31, 
2025
December 31, 
2024
Cash flows generated by/ (used in):
Operations:
Profit/ (loss) before tax 11.8 (279.1)
Adjustments for:
(Reversal of) impairment of investment in joint venture 7 (55.9) 436.7
Share of loss from investments in associates 8 2.9 38.7
Share of profit from investment in joint venture 7 (2.9) (226.0)
Unrealized result on commodity risk management contracts 29 (2.2) -
Net financial items 22/23 43.7 (2.7)
Depletion, depreciation and amortisation 5 209.0 -
Impairment charges 5 105.3 -
Taxes 24 (135.9) -
Other 2.8 (1.3)
Net cash generated/ (used) in operating activities before working capital 178.6 (33.7)
Changes in working capital 31 94.0 (14.8)
Net cash generated / (used) in operating activities 272.6 (48.5)
Investing:
Investments in oil and gas properties and intangible exploration assets 5/6 (75.6) (7.7)
Investments in other fixed assets (0.4) -
Distribution received from joint venture 7 60.0 36.0
Distribution received from associates 8 31.6 -
Equity investment in associates 8 - (88.6)
Loan repaid by / (provided to) associated company 26 4.5 (1.0)
Interest income received 4.2 7.6
Cash acquired from Meren Coop consolidation 4 380.4 -
Net cash generated/ (used) in investing activities 404.7 (53.7)
Financing:
Repayment RBL Facility (420.0) -
Repayment of principal portion of lease commitments 15 (0.7) (0.5)
Dividends paid to shareholders 13 (100.2) (22.6)
Repurchase of share capital 13 (8.3) (45.3)
Interest expense paid (34.8) -
Net cash used in financing activities (564.0) (68.4)
Effect of exchange rate changes on cash and   
cash equivalents denominated in foreign currency - -
Increase/ (decrease) in cash and cash equivalents 113.3 (170.6)
Cash and cash equivalents, beginning of the year 12 61.4 232.0
Cash and cash equivalents, end of the year 12 174.7 61.4
The notes are an integral part of the consolidated financial statements.

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PAGE 52
Report to Shareholders  |  December 31, 2025
NOTES TO CONSOLIDATED  
FINANCIAL STATEMENTS
For the years ended December 31, 2025, and December 31, 2024
(Expressed in millions of United States dollars unless otherwise indicated)
1. Incorporation and nature of business:
Meren Energy Inc. (collectively with its subsidiaries, “MER” or “Meren” or the “Company” or the “Group”) was incorporated on March 29, 1993, 
under the laws of British Columbia and is an international oil and gas exploration and production company based in Canada with oil and gas 
interests in Africa. The Company’s registered address is 25th Floor, 666 Burrard Street, Vancouver, B.C., Canada V6C 2X8. The Company changed 
its name to Meren Energy Inc. on May 14, 2025, and was previously called Africa Oil Corp. 
2. Basis of preparation:
A. Statement of compliance:
The Company prepares its consolidated financial statements in accordance with International Financial Reporting Standards as issued by the 
International Accounting Standards Board (“IFRS Accounting Standards”). The policies applied in these consolidated financial statements are 
based on IFRS Accounting Standards issued and outstanding as at February 24, 2026, the date the Board of Directors approved the statements.
B. Basis of measurement:
The consolidated financial statements have been prepared on the historical cost basis. Where there are assets and liabilities calculated on a 
different basis, this fact is disclosed in the material accounting policy. The Company uses the full cost method of accounting for exploration costs. 
Identifiable assets acquired and liabilities assumed in the transaction with BTG Oil & Gas were measured at its acquisition date fair value based 
on guidance in IFRS 13 as per note 4. Certain comparative figures have been reclassified to conform with the financial statements presentation 
in the current year following completion of the transaction with BTG. The Company has changed the presentation of its share of profit from 
investment in joint venture and associated companies in the Consolidated Statement of Net Income or Loss and Other Comprehensive Income 
or Loss. The Company has also changed the presentation of interest income received in the Consolidated Statement of Cash Flows. 
C. Functional and presentation currency:
These consolidated financial statements are presented in United States (US) dollars. The functional currencies of the Company’s individual 
entities are US dollars, which represents the currency of the primary economic environment in which the entities operate. 
The consolidated financial statements are expressed in millions of US dollars unless otherwise indicated. 
D. Use of estimates and judgements:
The preparation of financial statements in conformity with IFRS Accounting Standards requires management to make judgements, estimates 
and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual 
results may differ from these estimates. 
Information about significant areas of estimation and critical judgements in applying accounting policies that have the most significant effect 
on the amounts recognized in the consolidated financial statements are noted below, with further details of the assumptions contained in the 
relevant note. 
i. Classification of joint arrangements
These consolidated financial statements include transactions of non-operated Production Sharing Agreements (“PSAs”). The PSA transactions 
include the Group’s proportionate share of the PSAs assets, liabilities and expenses, with items of a similar nature on a line-by-line basis, from 
the date that participation in the PSA arrangements commenced. 
The Group has applied judgment in determining that it has joint control over the PSAs. This determination recognizes that all major decisions 
outside the original scope of the operations require unanimous approval by at least the Group and one or more of the PSAs partners. 
The Group has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions of 
the arrangement, such as approval of the capital expenditure program for each year and appointing, remunerating and terminating the key 
management personnel or service providers of the joint arrangement. The considerations made in determining joint control are similar to those 
necessary to determine control over subsidiaries.

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PAGE 53
Report to Shareholders  |  December 31, 2025
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
Classifying the arrangement requires the Group to assess its rights and obligations arising from the arrangement. Specifically, the Group 
considers: 
 ● The structure of the joint arrangement – whether it is structured through a separate vehicle; 
 ● When the arrangement is structured through a separate vehicle, the Group also considers the rights and obligations arising from; 
 » The legal form of the separate vehicle; 
 » The terms of the contractual arrangement; and
 » Other facts and circumstances (when relevant). 
As the Group has a proportionate share of the rights to the PSAs’ assets and the obligations for the PSAs’ liabilities, it classifies these interests 
as a Joint Operation under IFRS 11, and presents its proportionate share of the assets, liabilities, revenues and expenses on a line-by-line basis 
in the consolidated financial statements. 
This assessment often requires significant judgement, and a different conclusion on joint control and also whether the arrangement is a joint 
operation or a joint venture, may materially impact the accounting. 
If the Group did not have both joint control and a proportionate share of the rights to the PSAs’ assets and obligations for the PSAs’ liabilities, it 
would present only its net investment in the PSAs and its proportionate share of the PSAs’ net income in the consolidated financial statements.
ii. Accounting for leases and joint operations 
Where the Group participates in a joint operation, either as a lease operator or non-operator party, determining whether to recognize and 
whether to measure a lease obligation involves judgement and requires identification of which entity has primary responsibility for the lease 
obligations entered into in relation to the joint operation’s activities. 
Where the joint operation (including all parties to that arrangement) has the right to control the use of the identified asset and all parties have 
a legal obligation to make payments to the third-party supplier, each joint operation participant would recognize its proportionate share of the 
lease related balances. This may arise where all parties to an unincorporated joint operation sign the lease agreement, or the joint operation is 
some sort of entity or arrangement that can sign in its own name. 
However, where the Group is the lead operator and the sole signatory such that it is the one with the legal obligation to pay the third-
party supplier, it would recognize 100% of the lease-related balances on its balance sheet. The Group would then need to assess whether 
the arrangement with the non-operator parties contains a sublease. This assessment would be based on the terms and conditions of each 
arrangement and may be impacted by the legal jurisdiction in which the joint arrangement operates.
Regardless of whether there is a sublease or not, the Group, in case it acts as the lead operator, would continue to recognize the lease liability 
for as long as it remains a party to the arrangement with the third-party supplier and has primary obligation to the lease payments.
iii. Valuation of investments:
An investment in an associate or a joint venture is accounted for using the equity method from the date on which the investee becomes an 
associate or a joint venture. Investments in associates or joint ventures are initially recorded at cost. On acquisition of the investment in an 
associate or a joint venture, any excess of the cost of the investment over the share of the net fair value of the identifiable assets and liabilities 
of the investee is recognized as notional goodwill, which is included within the carrying amount of the investment. Significant assumptions 
developed by management used to determine the fair value of the non-current assets include estimates for the quantity of proved and probable 
oil and gas reserves, future commodity prices, operating and capital costs as well as discount rates. The proved and probable oil and gas reserves 
are prepared by the investee’s independent petroleum engineers (management’s experts). 
Where contingent consideration has been recognized in an investment in an associate or joint venture, any revisions to the contingent 
consideration estimates after the date of acquisition, which have been considered as changes in estimates in accordance with IAS 8, are 
accounted for on a prospective basis. Any change in the liability as a result of the revised cash flows is adjusted to the cost of the asset and, 
in accordance with paragraph 37 of IAS 8, recognized as part of the associate or joint venture carrying amount rather than in profit or loss.
iv. Recoverability of oil and gas properties
The Group assesses each asset or cash generating unit (CGU) (excluding goodwill, which is assessed annually regardless of indicators) each 
reporting period to determine whether any indication of impairment exists. Where an indicator of impairment exists, with reference to total 
proved and probable oil and gas reserves (‘2P’), a formal estimate of the recoverable amount is made, which is considered to be the higher of 
the fair value less costs to dispose and value in use. The assessments require the use of estimates and assumptions such as long-term oil prices, 
future production volumes, discount rates, operating costs, development costs, decommissioning costs, reserve volumes (see Hydrocarbon 
reserve and resource estimates) and operating performance (which includes production and sales volumes). These estimates and assumptions 
are subject to risk and uncertainty and changes in assumptions used in determining the recoverable amount could affect the carrying value of 
the related assets. 
Fair value is determined as the amount that would be obtained from the sale of the asset in an arm’s length transaction between knowledgeable 
and willing parties. Fair value for oil and gas properties is generally determined as the present value of estimated future cash flows arising 
from the continued use of the assets, which includes estimates such as the future development costs and eventual disposal, using assumptions 
that an independent market participant may take into account. Fair value for oil and gas properties is determined using a discounted cash flow 
model. Cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of 
money and the risks specific to the asset/CGU. Significant assumptions developed by management used to determine the fair value of the non-
current assets include estimates for the quantity of proved and probable oil and gas reserves, future commodity prices, operating and capital 
costs as well as discount rates. The proved and probable oil and gas reserves are prepared by the Company’s independent petroleum engineers 
(management’s experts).

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PAGE 54
Report to Shareholders  |  December 31, 2025
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
v. Impairment of joint ventures and associates
The amounts for investments in joint ventures and associates represents the Company’s equity interest in other entities, where there is either 
joint control or significant influence. The Company assesses investments in associates for impairment whenever changes in circumstances 
or events indicate that the carrying value may not be recoverable.  The process of determining whether there is an objective evidence of 
impairment considering circumstances or events which indicate that the carrying value may not be recoverable or calculating the recoverable 
amount requires judgement.  
An area in which the Company applied judgement prior to the completion of the transaction with BTG Oil & Gas to consolidate its interest 
in Meren Coop relates to the equity investment in joint venture. On acquisition, judgements and estimates were used in determining fair 
values on acquisition for the purposes of the notional purchase price allocation. Subsequently, in assessing whether there were any indicators 
of impairment the Company considered any effects of Meren Coop’s forward sales, the loan facility, and any operational and contractual 
implications on the future dividend stream when assessing for impairment indicators. 
An area in which the Company has applied judgement relates to the equity investments in associates. In assessing whether there are any 
indicators of impairment the Company considered the movements in share price of the associates listed on public markets, the results of 
exploration and appraisal activities and future plans for the operations.
vi. Hydrocarbon reserve and resource estimates
Oil and gas production assets, including facilities, are depleted on a units-of-production (“UoP”) basis at a rate calculated by reference to total 
proved and probable oil and gas reserves (“2P”) determined in accordance with Canadian National Instrument 51-101, Standards of Disclosure 
for Oil and Gas Activities (“NI 51-101”) and incorporating the estimated future development cost of developing and extracting reserves.  
The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, 
engineering, and economic data. 2P reserves are determined using estimates of oil and gas in place, recovery factors, operating expenses, future 
development costs and future commodity prices; the latter having an impact on the total amount of recoverable reserves and the proportion 
of the gross reserves which are attributable to the host government under the terms of the Production-Sharing Agreements. The Company’s 
reserves are evaluated annually and reported to the Company by its independent petroleum engineers (management’s experts).
The current long-term Brent oil price assumption used in the estimation of proved and probable oil and gas reserves is based on independent 
petroleum engineers  long-term oil price forward curve. 
As the economic assumptions used may change and, as additional geological information is obtained during the operation of a field, estimates 
of recoverable reserves may change.
vii.  Units-of-production depreciation of oil and gas properties
Oil and gas properties are depleted using the UoP-method over total estimated proved and probable oil and gas reserves and incorporating the 
estimated future development cost of developing and extracting reserves. This results in a depletion charge that is proportional to the depletion 
of the anticipated remaining production from the field. 
The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically 
recoverable reserves of the field at which the asset is located. These calculations require the use of estimates and assumptions, including the 
amount of recoverable reserves. 
The calculation of the UoP-rate of depreciation could be impacted to the extent that actual production in the future is different from current 
forecast production based on total estimated proved and probable oil and gas reserves, or change in future development cost estimates. 
Changes to proved and probable oil and gas reserves could arise due to changes in the factors or assumptions used in estimating reserves, 
including the effect on proved and probable oil and gas reserves of differences between actual commodity prices and commodity price 
assumptions or unforeseen operational issues.
viii. Exploration and evaluation costs 
Exploration and evaluation costs are initially capitalized as intangible exploration assets with the intent to establish commercially viable 
reserves. The Company is required to make significant estimates and judgements about the future events and circumstances regarding whether 
the carrying amount of intangible exploration assets exceeds its recoverable amount (see note 6).  
The carrying amounts of the Company’s exploration and evaluation costs are reviewed at each reporting date to determine whether there is any 
indication of impairment. Exploration and evaluation assets are assessed for impairment if facts and circumstances suggest that the carrying 
amount exceeds the recoverable amount. Should the carrying amount exceed the recoverable amount, an impairment loss is recognized. 
Significant assumptions developed by management used to determine the recoverable amount include estimates for the quantity of contingent 
resources, future commodity prices, production forecasts, operating expenses, development costs, the likelihood of a successful farm out 
process, the timing of financial investment decision (“FID”) and the discount rate. The contingent resources and production rates are prepared 
by the Company’s independent petroleum engineers (management’s experts). 
Exploration and evaluation assets are assessed if facts and circumstances suggest that an impairment loss recognized in prior periods may no 
longer exist or may have decreased. An impairment reversal is recognized if there has been an increase in the asset’s recoverable amount since 
the last impairment loss was recognized.  
The changing worldwide demand for energy could result in a change in the assumptions used to determine the recoverable amount and 
could affect estimating the future cash flows which could impact the carrying amount of the Company’s intangible exploration assets. The 
timing of when global energy markets transition from carbon-based sources to alternative energy sources is highly uncertain. Environmental 
considerations are built into our estimates through the use of significant assumptions in estimating fair value including future commodity prices 
and discount rates. The energy transition could impact the future prices of commodities and discount rates used to appraise oil and gas projects. 
Pricing assumptions used in the determination of recoverable amounts incorporate market expectations and the evolving worldwide demand 
for energy.

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PAGE 55
Report to Shareholders  |  December 31, 2025
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
ix. Provision for site restoration:
Amounts used in recording a provision for site restoration are based on current legal and constructive requirements, current technology, price 
levels for the removal of facilities and plugging and abandoning of wells. Due to changes to these items, the future cash outflows in relation 
to the site decommissioning and restoration can be difficult to determine. To reflect the effects due to changes in legislation requirements, 
technology and price levels, the carrying amounts of site restoration provisions are reviewed on a regular basis.
On fields where the Group is required to contribute to site restoration costs, a provision is recorded to recognize the future commitment. An 
asset is created, as part of oil and gas interests, to represent the discounted value of the anticipated site restoration liability and depleted over 
the life of the field on a unit of production basis. The corresponding accounting entry to the creation of the asset recognizes the discounted 
value of the future liability. The discount applied to the anticipated site restoration liability is subsequently released over the life of the field 
and is charged to finance expense. Changes in site restoration costs and reserves are treated prospectively and consistent with the treatment 
applied upon initial recognition (see note 14).
x. Revenue recognition 
Judgement is required in determining when and how much revenue to recognize from contracts with customers. While the Group has determined 
that all revenue from contracts with customers is earned at a point in time, there is judgement involved in this consideration. Contractual 
arrangements for the sale of different products or with different terms may result in revenue being recognized over time. 
There is also judgement involved in assessing whether the Group is the principal or agent in revenue transactions. In determining that the Group 
is acting as principal, the terms of the agreements were carefully considered and it was concluded that the Group controls the product before 
it is transferred to the customer. In alternate arrangements, the Group could be determined to be acting as agent. 
Under the terms of existing contracts, the Group has determined that shipping or transportation services are not being provided to the 
customer, and that the only performance obligations are for the sale of crude oil and natural gas. Judgement is required in determining whether 
shipping is being provided as a service, and this impacts on the identification of performance obligations, whether all performance obligations 
are recognized at a point in time or over time, and the overall timing of revenue recognition.
Finally, judgement is required to determine whether the contractual arrangements contain only variable consideration, or also embedded 
derivatives, and if variable consideration, whether to exercise the constraint.
xi. Taxes
Judgement is required to determine which arrangements are considered to be a tax on income as opposed to production costs. Judgement is 
also required to determine whether deferred tax assets are recognized in the statement of financial position. Deferred tax assets, including 
those arising from tax losses carried forward, require management to assess the likelihood that the Group will generate sufficient taxable 
earnings in future periods in order to utilize recognized deferred tax assets. 
To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Group to realize the net deferred 
tax assets recorded at the reporting date could be impacted. In addition, future changes in tax laws in the jurisdictions in which the Group 
operates could limit the ability of the Group to obtain tax deductions in future periods.
xii.  Share based compensation
The estimated fair value of Performance share units (“PSUs”) is calculated based on non-market performance conditions set by the Company 
which are initially determined at the time of grant. The Company assesses the progress of reaching the individual performance conditions during 
each reporting period. PSUs cliff vest three years from the date of grant, at which time the Board of Directors will assign a performance multiple 
ranging from nil to 200% to determine the ultimate vested number of PSUs. The awards are revalued every quarter based on the Company’s 
share price and an estimate of the performance conditions at the quarter end. It is anticipated that PSU settlements will be made by issuing 
shares from treasury or cash, at the discretion of the Board of Directors (see note 21). 
The estimated fair value of the Restricted share units (“RSUs”) is initially determined at the time of grant. The awards are revalued every quarter 
based on the Company’s share price. RSUs may be settled in shares issued from treasury or cash, at the discretion of the Board of Directors 
(see note 21).
xiii. Contingencies
Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome of a future event. 
The assessment of contingencies requires the application of judgements and estimates including the determination of whether a present 
obligation exists, and the reliable estimation of the timing and amount of cash flows required to settle the contingencies.

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Report to Shareholders  |  December 31, 2025
xiv. Going concern
These consolidated financial statements for the year ended December 31, 2025, have been prepared on a going concern basis, which assumes 
that the Company will be able to realize its assets and discharge its liabilities in the normal course of business as they become due.
3. Material accounting policies:
The accounting policies set out below have been applied consistently to all years presented in these consolidated financial statements and have 
been applied consistently by the Company and its subsidiaries.
A. Basis of consolidation:
i. Subsidiaries:
Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating 
policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that are currently exercisable are 
taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control 
commences until the date that control ceases.
ii. Jointly controlled operations and jointly controlled assets:
Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties 
to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The 
Company recognizes its share of assets, liabilities, revenues and expenses of a joint operation. A significant portion of the Company’s operating 
cash flows is derived through joint operations which are involved in the development and production of crude oil and gas in Nigeria. Joint 
ventures arise when the Company has rights to the net assets of the arrangement. Joint ventures are accounted for under the equity method.
iii. Transactions eliminated on consolidation: 
Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in 
preparing the consolidated financial statements.  
B. Equity method:
Investments in joint ventures and associates are accounted for using the equity method. Investments of this nature are recorded at original cost. 
Investments in joint ventures or associates which arise from a loss in control of a subsidiary are recorded at fair value on the date of the loss 
of control. The investment is adjusted at each reporting date for the Company’s share of the profit or loss of the investment after the date of 
acquisition. The investor’s share of the profit or loss of the investee is also recognized in the Company’s Statement of Net Income or Loss and 
Other Comprehensive Income or Loss. Distributions received reduce the carrying amount of the investment.  
The Company assesses its investments in joint ventures and associates for an objective evidence of impairment considering circumstances 
or events which indicate that the carrying value may not be recoverable. If such circumstances or events exist, the carrying amount of the 
investment is compared to its recoverable amount. The recoverable amount is the higher of the investment’s fair value less costs to dispose and 
its value in use. The investment is written down to its recoverable amount when its carrying amount exceeds the recoverable amount.
C. Business combinations
Business combinations are accounted for using the acquisition method as at acquisition date, which is the date on which control is transferred 
to the Group. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value 
and the amount of any previously held interest in the acquiree. 
Under the acquisition method the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and 
measured at their fair value at the date of acquisition. Fair value for oil and gas properties is generally determined as the present value of 
estimated future cash flows arising from the continued use of the assets using a discounted cash flow model. Any excess of the purchase price 
plus any non-controlling interest over the value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over 
the value of the net assets acquired is credited to net earnings. When a business combination is achieved in stages, the Company re-measures 
its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in the Statement of Net Income or 
Loss and Other Comprehensive Income or Loss. Contingent consideration transferred in a business combination is measured at fair value on 
the date of acquisition. 
Acquisition related costs are expensed as incurred and included in general and administrative expenses, except if related to the issue of debt 
or equity securities. 
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Report to Shareholders  |  December 31, 2025
D. Oil and gas properties
Oil and gas properties are aggregated exploration and evaluation tangible assets, and development expenditures associated with the production 
of proved and probable oil and gas reserves. Development expenditure on the construction, installation or completion of infrastructure facilities 
such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalized 
within ‘Oil and gas properties’. These assets are depreciated/amortized on a UoP basis over the 2P reserves of the field concerned from the 
commencement of production, taking into account future development expenditures necessary to bring those reserves into production.
i. Initial recognition
Oil and gas properties are stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset 
comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the 
decommissioning obligation and, for qualifying assets, borrowing costs.
Qualifying assets are those that necessarily take a substantial period of time to build and from which future benefits accrue to the Group. 
Capitalization continues up to the date that all the substantial activities necessary to get the asset ready for its intended use are complete.
Capitalized expenditure relating to the Group’s carried interest is recorded in line with the Group’s accounting policy. 
The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. 
Subsequent costs are included in the asset’s carrying amount or recognized as a separate asset, as appropriate, only when it is probable that 
future economic benefits associated with the item will flow to the Group and the cost can be measured reliably. The carrying amount of the 
replaced part is derecognized.
When a development project moves into the production stage, the capitalization of certain construction/development costs ceases and costs are 
expensed, except for costs which qualify for capitalization relating to oil and gas property asset additions, improvements or new developments.
ii. Depletion
Oil and gas properties are depleted from the commencement of production, on a UoP basis, which is the ratio of oil and gas production in the 
period to the estimated quantities of the 2P reserves at the end of the period plus the production in the period, on a field-by-field basis. 
Facilities included in oil and gas production assets are depreciated on a UoP basis over the economic useful life of the field concerned. Costs 
used in the UoP calculation comprise the net carrying amount of capitalized costs plus the estimated future field development costs. 
Changes in the estimates of reserves or future field development costs are dealt with prospectively. Oil and gas volumes are considered 
produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the field storage 
tank. Rights and concessions are depleted on the UoP basis over the total proved and probable oil and gas reserves of the relevant area.
iii. Maintenance, inspection and repairs
Expenditure on major maintenance refits, inspections or repairs comprises the cost of replacement assets or parts of assets, inspection costs 
and overhaul costs. Where an asset or part of an asset, that was separately depreciated and is now written off, is replaced and it is probable that 
future economic benefits associated with the item will flow to the Group, the expenditure is capitalized. Where part of the asset replaced was 
not separately considered as a component and therefore not depreciated separately, the replacement value is used to estimate the carrying 
amount of the replaced asset(s) which is immediately written off. Inspection costs associated with major maintenance programs are capitalized 
and amortized over the period to the next inspection. All other day-to-day repairs and maintenance costs are expensed as incurred.
iv. Disposal/ sale of assets
Net proceeds from any disposal of oil and gas interests are recorded as a gain or loss on disposal recognized in the Statement of Net Income 
or Loss and Other Comprehensive Income or Loss to the extent that the net proceeds exceed or are less than the appropriate portion of the 
net capitalized costs of the asset. 
E. Recoverability of oil and gas properties
The Group assesses each asset or cash generating unit (CGU) (excluding goodwill, which is assessed annually regardless of indicators) each 
reporting period to determine whether any indication of impairment exists. Where an indicator of impairment exists, with reference to total 
proved and risk-adjusted probable reserves, a formal estimate of the recoverable amount is made, which is considered to be the higher of 
the fair value less costs to dispose and value in use. The assessments require the use of estimates and assumptions such as long-term oil 
prices (considering current and historical prices, price trends and related factors), discount rates, operating costs, future capital requirements, 
decommissioning costs, exploration potential, reserves (see Hydrocarbon reserve and resource estimates above) and operating performance 
(which includes production and sales volumes). These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a 
possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs. 
Fair value is determined as the amount that would be obtained from the sale of the asset in an arm's length transaction between knowledgeable 
and willing parties. Fair value for oil and gas properties is generally determined as the present value of estimated future cash flows arising from 
the continued use of the assets, which includes estimates such as the cost of future expansion plans and eventual disposal, using assumptions 
that an independent market participant may take into account. Cash flows are discounted to their present value using a discount rate that 
reflects current market assessments of the time value of money and the risks specific to the asset/CGU.
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Report to Shareholders  |  December 31, 2025
F. Intangible exploration assets
i. Pre-exploration expenditures:
Costs incurred prior to obtaining the legal rights to explore an area are recognized in the Statement of Net Income or Loss and Other 
Comprehensive Income or Loss as incurred. 
ii. Exploration expenditures:
Exploration expenditures include costs associated with the acquisition of a license interest, directly attributable general and administrative 
costs, expenditures incurred in the process of determining oil and gas exploration targets, and exploration drilling costs. All exploration 
expenditures with common geological structures and shared infrastructure are accumulated together within intangible exploration assets. The 
Company does not aggregate exploration expenditures above the segment level for the purpose of impairment testing.  Costs are not depleted 
until such time as the exploration phases on the license area are complete, the license area is relinquished, or commercially viable reserves have 
been discovered and extraction of those reserves is determined to be technically feasible.
If commercial reserves are established and technical feasibility for extraction demonstrated, then the related capitalized intangible exploration 
costs are transferred into a CGU within oil and gas interests subsequent to determining that the assets are not impaired (see “Impairment” 
below). Where results of exploration drilling indicate the presence of hydrocarbons which are ultimately not considered commercially viable, all 
related costs are recognized in the Statement of Net Income or Loss and Other Comprehensive Income or Loss.
Net proceeds from any disposal or farmout of an intangible exploration asset are recorded as a reduction in intangible exploration assets. 
iii. Development and production costs:
All costs incurred after the technical feasibility and commercial viability of producing hydrocarbons has been demonstrated are capitalized 
within oil and gas interests on a CGU basis. 
G. Impairment:
i. Financial assets carried at amortized cost:
A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset 
is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash 
flows of that asset.
The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the 
nature of its financial assets, the Company measures loss allowances at an amount equal to expected lifetime ECLs.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and 
the present value of the estimated future cash flows discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively 
in groups that share similar credit risk characteristics.
All impairment losses are recognized in the Statement of Net Income or Loss and Other Comprehensive Income or Loss. 
An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For 
financial assets measured at amortized cost the reversal is recognized in the Statement of Net Income or Loss and Other Comprehensive 
Income or Loss.
ii. Non-financial assets:
The carrying amounts of the Company’s non-financial assets, including the Company’s equity investments, other than oil and gas properties, 
intangible exploration assets, inventories and deferred tax assets, are reviewed at each reporting date to determine whether there is any 
indication of impairment or reversals of impairment. 
Intangible exploration assets are assessed for impairment when they are reclassified to property and equipment, as oil and gas properties, 
and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.  If any such indication exists, then the 
asset’s recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives or that are not yet available for use, 
an impairment test is completed each reporting period.
For the purpose of impairment testing, assets are grouped together into a CGU.  The recoverable amount of an asset or a CGU is the greater 
of its value in use and its fair value less costs to dispose. 
In assessing value in use, the estimated future cash flows are discounted to their present value using a post-tax discount rate that reflects 
current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference 
to the present value of the future cash flows expected to be derived from production of 2P reserves. In determining fair value less costs 
to dispose, recent market transactions are taken into account, if available, and a post-tax discount rate is applied. In the absence of such 
transactions, an appropriate valuation model is used.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses 
are recognized in the Statement of Net Income or Loss and Other Comprehensive Income or Loss. Impairment losses recognized in respect of 
CGU’s are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the 
other assets in the unit (group of units) on a pro rata basis. 
If there is an indicator that a previous impairment may no longer exist or may have decreased, the recoverable amount of the relevant asset 
or its CGU is calculated and compared against the carrying amount. The impairment is reversed to the extent that the asset or its CGU’s 
recoverable amount does not exceed the carrying amount that would have been determined if no impairment had been recognized. An 
impairment reversal is recognized in the Statement of Net Income or Loss and Other Comprehensive Income or Loss. 
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Report to Shareholders  |  December 31, 2025
Other non-financial assets are subject to impairment tests whenever events or changes in circumstances indicate that their carrying amount 
may not be recoverable.  Where the carrying value of an asset exceeds its recoverable amount (i.e. the higher of value in use and fair value less 
costs to sell), the asset is written down accordingly.
H. Leases
Leases are accounted for by recognising a right-of-use asset and a lease liability except for: 
 ● Leases of low value assets; and 
 ● Leases with a duration of 12 months or less. 
Lease liabilities are measured at the present value of the contractual payments due to the lessor over the lease term, discounted using the 
interest rate implicit in the lease or if that rate cannot be readily determined the discount rate is determined by reference to the Company’s 
incremental borrowing rate on commencement of the lease. Variable lease payments are only included in the measurement of the lease 
liability if they depend on an index or rate. In such cases, the initial measurement of the lease liability assumes the variable element will remain 
unchanged throughout the lease term. Other variable lease payments are expensed in the period to which they relate. 
On initial recognition, the carrying value of the lease liability also includes: 
 ● amounts expected to be payable under any residual value guarantee; 
 ● the exercise price of any purchase option granted in favour of the Company if it is reasonably certain to assess that option; 
 ● any penalties payable for terminating the lease, if the term of the lease has been estimated on the basis of termination option being 
exercised. 
Right of use assets are initially measured at the amount of the lease liability, reduced for any lease incentives received, and increased for: 
 ● lease payments made at or before commencement of the lease; 
 ● initial direct costs incurred; and 
 ● the amount of any provision recognized where the Company is contractually required to dismantle, remove or restore the leased asset. 
Subsequent to initial measurement lease liabilities increase as a result of interest charged at a constant rate on the balance outstanding and 
are reduced for lease payments made. Right-of-use assets are amortised on a straight-line basis over the remaining term of the lease or over 
the remaining economic life of the asset if this is judged to be shorter than the lease term. 
When the Company revises its estimate of the term of any lease, it adjusts the carrying amount of the lease liability to reflect the payments to 
make over the revised term, which are discounted using a revised discount rate. In this case an equivalent adjustment is made to the carrying 
value of the right-of-use asset, with the revised carrying amount being amortised over the remaining (revised) lease term. If the carrying 
amount of the right-of-use asset is adjusted to zero, any further reduction is recognised in profit or loss.
I. Investments held for sale
Investments held for sale are measured at the lower of their carrying amount and fair value less costs to sell. Costs to sell are the incremental 
costs directly attributable to the disposal of an asset. The criteria for held for sale classification is regarded as met only when the sale is highly 
probable, and the asset or disposal group is available for immediate sale in its present condition. The Company has committed to the plan to 
dispose of the asset and the disposal is expected to be completed within one year from the date of the classification.
J. Inventories 
Inventories mainly comprise materials. These are stated at the lower of cost and net realizable value. Purchase cost includes costs of bringing 
material inventory to their present location and condition, including freight and handling charges. Cost is determined using the weighted 
average method. Net realizable value is the estimated selling price in the ordinary course of business, less selling expenses. 
If carrying value exceeds the net realizable amount, a write down is recognized. The write-down may be reversed in a subsequent period if the 
circumstances which caused it no longer exist.
K. Trade receivables 
Trade receivables are amounts due from customers for crude oil and gas sold or services performed in the ordinary course of business and 
represent the Group’s right to an amount of consideration that is unconditional (i.e., only the passage of time is required before payment of the 
consideration is due). Trade receivables are recognized initially at fair value and subsequently measured at amortized cost using the effective 
interest method, less any allowance for expected credit losses.
L. Cash and cash equivalents
Cash and cash equivalents includes cash on hand and deposits held with financial institutions with maturities of three months or less that are 
readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. 
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Report to Shareholders  |  December 31, 2025
M. Financial instruments:
Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial 
assets are derecognized when the rights to receive cash flows from the assets have expired or have been transferred and the Company has 
transferred substantially all risks and rewards of ownership.  Financial assets and liabilities are offset and the net amount is reported in the 
Balance Sheet when there is a legally enforceable right to offset the recognized amounts and there is an intention to settle on a net basis or 
realize the asset and settle the liability simultaneously.
At initial recognition, the Company classifies its financial instruments either as fair value through profit and loss, fair value through other 
comprehensive income or at amortized cost depending on the purpose for which the instruments were acquired. The Company has instruments 
recognized at fair value through profit and loss and amortized cost.
Financial assets and liabilities at amortized cost: 
Financial assets and liabilities at amortized cost include accounts receivable, loans receivable, accounts payable and debt and are initially 
recognized at the amount required to be received or paid, less, when material, a discount to reduce the receivables or payables to fair value. 
Subsequently, these assets and liabilities are measured at amortized cost using the effective interest method. Financial assets and liabilities 
are classified as current assets and liabilities if payment is due within twelve months. Otherwise, they are presented as non-current assets and 
liabilities.
Financial assets at fair value through profit or loss (FVTPL): 
Financial assets measured at FVTPL are assets which do not qualify as financial assets at amortized cost or at fair value through other 
comprehensive income.
N. Derivative financial instruments and hedge accounting 
The Group is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is 
commodity price risk. The Group uses forward commodity contracts and derivative financial instruments to hedge its commodity price risk. 
On the forward commodity contracts, hedge accounting is not considered applicable as the own-use exception applies: the Group does not enter 
into physical oil contracts other than to meet the Group’s expected sales requirements. These arrangements therefore fall outside the scope 
of IFRS 9 and are classified as normal sales contracts that are accounted for on an accrual basis. 
The Group’s derivative financial instruments are initially recognized at fair value on the date on which the derivative contracts are entered into 
and are subsequently remeasured at fair value, with subsequent changes in fair value recognized in profit and loss. Derivatives are carried as 
financial assets when the fair value is positive and as financial liabilities when the fair value is negative.
O. Provisions:
A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, 
and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the 
expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the 
liability. Provisions are not recognized for future operating losses.
i. Provision for site restoration:
On fields where the Group is required to contribute to site restoration costs, a provision is recorded to recognize the future commitment, 
which is recorded at the discounted value of the future liability. The discount applied to the anticipated site restoration liability is subsequently 
released over the life of the field and is charged to finance expense. Changes in site restoration costs and reserves are treated prospectively 
and consistent with the treatment applied upon initial recognition.
The corresponding accounting entry to the creation of the liability is the recognition of an asset, as part of oil and gas interests, to represent 
the discounted value of the anticipated site restoration liability and depleted over the life of the field on a unit of production basis. 
ii. Contingent Consideration:
The amount recognized as contingent consideration is the best estimate of the consideration required to settle the obligation at the reporting 
date, taking into account the risks and uncertainties surrounding the obligation. 
The provision for contingent consideration is partly related to the initial acquisition of 50% interest in Meren Coop. At the date of this acquisition, 
an estimate of the fair value of the contingent consideration was determined and included as part of the cost of the acquisition. Subsequent to 
this acquisition, contingent consideration is accounted for as a financial liability in line with IFRS 9. Until completion of the transaction with BTG 
Oil & Gas to consolidate its interest in Meren Coop, the change in the liability, as a result of the revised cash flows, was adjusted to the cost of 
the investment and recognized as part of the investment’s carrying amount rather than in profit or loss.  
The provision for contingent consideration is also partly related to the Amended and Restated Joint Sale Agreement with Petrobras International 
Braspetro B.V. (“Petrobras”) dated October 31, 2018, relating to the acquisition of the remaining 50% in Meren Coop.
The estimates involved in assessing the value of the contingent consideration include the expected timing of payments, the expected 
settlement value, the likelihood of settlement and the probability of the assessed outcomes occurring. There is significant judgement used in 
the determination of these estimates.
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iii. Performance share units (“PSUs”):
The Company has a long-term incentive plan (see note 21). Eligible plan participants may be granted PSUs. PSUs are accounted for as cash-
based awards and recorded as a liability. The estimated fair value of the awards is initially determined at the time of grant. The awards are 
revalued every quarter based on the Company’s share price and the change is recorded as share-based compensation in the Statement of 
Net Income or Loss and Other Comprehensive Income or Loss. The estimated fair value of the awards is calculated based on non-market 
performance conditions set by the Company which are initially determined at the time of grant. The Company assesses the progress of reaching 
the individual performance conditions during each reporting period. PSUs cliff vest three years from the date of grant and the estimated fair 
value of the grant will be expensed evenly throughout the remaining vesting period. PSUs may be settled in shares issued from treasury or cash, 
at the discretion of the Board of Directors.
iv. Restricted share units (“RSUs”):
The Company has a long-term incentive plan (see note 21). Eligible plan participants may be granted RSUs. RSUs are accounted for as cash-
based awards and recorded as a liability. The estimated fair value of the awards is initially determined at the time of grant. The awards are 
revalued every quarter based on the Company’s share price and the change is recorded as share-based compensation in the Statement of Net 
Income or Loss and Other Comprehensive Income or Loss. RSUs granted to Non-Executive Directors cliff vest three years from the date of 
grant. The estimated fair value of RSUs are expensed evenly throughout the remaining vesting period. RSUs may be settled in shares issued 
from treasury or cash, at the discretion of the Board of Directors. 
P. Long term debt:
Long-term debt is initially measured at fair value less transaction costs that are directly attributable to the acquisition or issue of the debt. 
Subsequently, long-term debt is measured at amortized cost using the effective interest method. Long-term debt is classified as current if the 
liability is due to be settled within twelve months from the reporting date. All other debt is classified as non-current.
Q. Trade and other payables
Trade payables are obligations to pay for goods and services that have been acquired in the ordinary course of business from suppliers. Trade 
payables are presented as current liabilities, unless payment is not due within 12 months after the reporting period. They are recognized initially 
at their fair value and subsequently measured at amortized cost using the effective interest method.
R. Dividends 
Dividend liabilities are recognized when the Company’s shareholders have the right to receive the payment when the dividend is approved by 
the Board of Directors of the Company.
S. Sales of crude oil and natural gas
Revenue from contracts with customers is recognized when or as the Group satisfies a performance obligation by transferring a promised 
good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. As such, revenue 
is recognized when control of the goods or service transfers to the customer, it is probable that the economic benefits will flow to the Group 
and the revenue can be reliably measured. 
The measurement of revenue, when a performance obligation is satisfied, is based on the amount of the transaction price (excluding estimates 
of variable consideration that are constrained) that is allocated to that performance obligation, excluding discounts, sales taxes, excise duties 
and similar levies. 
The Group assesses its revenue arrangements against specific criteria in order to determine if it is acting as principal or agent. If the Group acts 
in the capacity of an agent rather than as the principal in a transaction, then the revenue recognized is the net amount of commission made by 
the Group. The Group has concluded that it is acting as a principal in all of its revenue arrangements, as described below:
Revenue from the sale of crude oil and natural gas is recognized when control of the goods transfers to the customer. The transfer of control 
of the crude oil and natural gas sold usually coincides with title passing to the customer and the customer taking physical possession. This 
generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. 
Crude oil transaction prices under forward contracts are based on a contract price for the Dated Brent component plus or minus a differential. 
In most of the Group’s oil offtake contracts, the Dated Brent component of the forward price at the time of entering the contract is not fixed 
but determined on or around the date of the lifting for spot cargos either on an average monthly basis, 5-days after bill of lading date or similar 
pricing mechanism. If the Group wants to utilize the oil offtake contract for commodity risk management, it can either fix the Dated Brent 
component or utilize a trigger pricing mechanism. For the trigger pricing mechanism, when the forward price curve falls below a certain trigger 
price for a certain month, this mechanism provides an irrevocable instruction to an offtaker to fix the Dated Brent price component of a cargo. 
The trigger price is based on a percentage of the Brent forward curve at the time the instruction was given for the month of the expected lifting. 
If the forward price curve does not fall below that threshold, the respective cargo is sold at spot.
The performance obligation is satisfied and payment is due upon delivery, FOB, to the buyer. At this point in time, at the bill of lading date, a 
trade receivable is recognized and there are generally 30 days between revenue recognition and payment. There are no obligations for returns, 
refunds, warranties nor other obligations when control has been transferred. The Group principally satisfies its performance obligations at a 
point in time. 
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Report to Shareholders  |  December 31, 2025
Revenue from crude oil transactions not covered under oil offtake contracts, arises from the production and lifting of crude oil on an entitlements 
basis. Under the entitlements method, revenue reflects the Group’s share of production under the terms of the relevant production sharing 
contracts, regardless of which participant has actually made the sale and invoiced the production. This is achieved by applying the following 
approach in dealing with imbalances between actual sales and entitlements. 
 ● Crude oil entitlement underlifts are recognized at the market price of oil at the balance sheet date. The excess of product sold during the 
period over the participant’s ownership share of production is recognized by the Group (acting as underlifter) as an asset in trade and other 
receivables with a corresponding credit to cost of sales. The Group’s underlift receivable is the right to receive additional oil from future 
production without the obligation to fund the production of that additional oil.
 ● Crude oil entitlement overlifts are treated as a purchase of crude oil by the overlifter from the underlifter and are also recognized at the 
market price of oil at the balance sheet date. The excess of product purchased during the period over the participant’s ownership share of 
production is recognized by the Group (acting as overlifter) as a liability in trade and other payables with a corresponding charge to cost of 
sales. An overlift liability is the obligation to deliver oil out of the Group’s equity share of future production. 
Revenues resulting from the production of oil under PSAs is recognized for those amounts relating to the Group’s cost recoveries and the 
Group’s share of the remaining production. 
T. Royalties
Obligations arising from royalty arrangements and other types of taxes that do not satisfy the criteria of IAS 12 ‘Income Taxes’ are accrued 
or paid and included in production costs. This is considered to be the case when the royalties are imposed under government authority and 
the amount payable is based on physical quantities produced or as a percentage of revenue, rather than taxable income. In some cases, the 
equivalent amount of royalties is also presented in revenues to differentiate between the portion of revenue lifted by the operator on behalf of 
the Group to settle the Group’s royalty liabilities and the associated royalties as part of production costs. In cases where the Group itself pays 
for the royalties in cash, these are included in production costs as a single line item.
U. Production costs 
The costs of producing oil are charged to the income statement in the period in which they are incurred. Production costs include movements 
in underlift and overlift balances.
V. Employee benefits
Employee benefits are recognized as they accrue in the Statement of Net Income or Loss and Other Comprehensive Income or Loss, based on 
the terms of employment.
W. Finance income and expenses:
Finance income and expenses are recognized as they accrue in the Statement of Net Income or Loss and Other Comprehensive Income or Loss, 
using the effective interest method.
X. Income tax:
Income tax expense comprises current and deferred tax. Income tax expense is recognized in the Statement of Net Income or Loss and Other 
Comprehensive Income or Loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting 
date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and 
liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized for: 
 ● temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and that affects 
neither accounting nor taxable profit or loss. 
 ● temporary differences related to investments in subsidiaries, associates and joint arrangements to the extent that the Group is able to 
control the timing of the reversal of the temporary differences and it is probable that they will not reverse in the foreseeable future;
 ● taxable temporary differences arising on the initial recognition of goodwill. 
Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that 
have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable 
right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they 
intend to settle current tax liabilities and assets on a net basis, or their tax assets and liabilities will be realized simultaneously. 
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary 
difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable 
that the related tax benefit will be realized.
On May 23, 2023, the International Accounting Standards Board (“IASB”) issued an amendment to IAS 12 Income Taxes in response to International 
Tax Reform and specifically the Pillar Two Global Anti-Base Erosion Rules (“Pillar Two Rules”) published by the Organization for Economic Co-
operation and Development (“OECD”). The Amendments introduce a mandatory temporary exception to the accounting for deferred taxes 
arising from the jurisdictional implementation of the Pillar Two model rules; and disclosure requirements for affected entities to help users of 
the financial statements better understand an entity’s exposure to Pillar Two income taxes arising from that legislation, particularly before its 
effective date. The Company adopted the mandatory temporary exception immediately. The remaining disclosure requirements have no effect 
on the Company’s consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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PAGE 63
Report to Shareholders  |  December 31, 2025
Y. Earnings per share:
Basic earnings per share is calculated by dividing net income/(loss) attributable to the common shareholders by the weighted average number 
of Common Shares outstanding during the year. Diluted earnings per share is determined by adjusting the net income/(loss) attributable to the 
common shareholders and the weighted average number of Common Shares outstanding for the effects of dilutive instruments such as options 
and Long Term Incentive Plans (“LTIP”) granted to employees.  The weighted average number of diluted shares is calculated in accordance 
with the treasury stock method. The treasury stock method assumes that the proceeds received from the exercise of all potentially dilutive 
instruments are used to repurchase Common Shares at the average market price. The PSUs are considered to be contingently issuable and 
are included in the calculation of diluted EPS as if the conditions of the contingency are deemed to have been met based on the information 
available at the end of the reporting period.  PSUs are only included in the diluted EPS calculation if the effect is dilutive. RSUs are included in 
full in the diluted EPS calculation only if the effect is dilutive.
Z. Foreign currency
Monetary assets and liabilities denominated in foreign currencies are translated into US dollars at exchange rates prevailing at the balance 
sheet date and non-monetary assets and liabilities are translated at rates in effect on the date of the transaction. Revenues and expenses are 
translated at exchange rates at the date of transaction. Exchange gains or losses arising from translation are included in the Statement of Net 
Income or Loss and Other Comprehensive Income or Loss.
AA. New and amended standards adopted by the Company:
The Company has applied the following standards and amendments for the first time for its annual reporting period commencing January 1, 
2025:
 ● IAS 21 - Lack of Exchangeability. The amendments help entities to determine whether a currency is exchangeable into another currency, and 
which spot exchange rate to use when it is not. There was no material impact to the Company’s financial statements.
AB. New standards and interpretations not yet adopted:
Certain new accounting standards and amendments to accounting standards have been published that are not mandatory for December 31, 
2025, reporting periods and have not been early adopted by the Company. The Company’s assessment of the impact of these new standards 
and amendments is set out below:
 ● IFRS 18 Presentation and Disclosure in Financial Statements - on April 9, 2024, the International Accounting Standards Board (IASB) issued 
IFRS 18 Presentation and Disclosure in Financial Statements, which aims to improve how companies communicate their financial statements, 
with a focus on information about financial performance in the statement of profit or loss. 
The standard adds new subtotals, categories for income and expenses, and mandates disclosure of management performance measures. 
It also enhances rules around aggregation and disaggregation. Adoption is retrospective, and the Corporation is currently assessing system 
changes, preparing draft disclosures, and planning comparative restatements ahead of the January 1, 2027, effective date;
 ● Amendments to the Classification and Measurement of Financial Instruments – Amendments to IFRS 9 and IFRS 7 (effective for annual 
periods beginning on or after January 1, 2026);
 ● Annual improvements to IFRSs: Volume 11 (effective for annual periods beginning on or after January 1, 2026);
 ● IFRS 19 Subsidiaries without Public Accountability: Disclosures (effective for annual periods beginning on or after January 1, 2027).
Apart from IFRS 18, these amendments are not expected to have a material impact on the entity in the current or future reporting periods and 
on foreseeable future transactions. 
4. Business combination:
On March 19, 2025, the Company completed the transaction with BTG Oil & Gas to consolidate its interest in Meren Coop. The transaction 
was originally announced on June 24, 2024. The acquisition increased the Company’s ownership in core cash generating assets and brought 
in a new, strategically aligned cornerstone investor, BTG Pactual. It is also expected to enable enhanced shareholder returns and the creation 
of a materially stronger growth proposition. The acquisition was completed by way of amalgamation whereby BTG Oil & Gas exchanged its 50 
percent interest in Meren Coop, held through its fully owned subsidiary BTG Pactual Holding S.à.r.l., in exchange for 239,828,655 newly issued 
shares in the Company. The primary assets acquired are an indirect 8% interest in Petroleum Mining License ("PML") 52 as well as Petroleum 
Prospecting License (“PPL”) 2003 and an indirect 16% interest in PMLs 2, 3 and 4 as well as PPL 261. PML 52 and PPL 2003 are operated by 
affiliates of Chevron and covers part of the producing Agbami field. PMLs 2, 3 and 4 and PPL 261 are operated by affiliates of TotalEnergies 
and contain the producing Akpo and Egina fields as well as the Preowei and Egina South discoveries.
The acquisition date for accounting purposes corresponds to the completion of the transaction on March 19, 2025. The acquisition is regarded 
as a business combination and has been accounted for using the acquisition method of accounting in accordance with IFRS 3. A final purchase 
price allocation (“PPA’’) has been performed to allocate the consideration to fair value of assets acquired and liabilities assumed. The PPA is 
performed as of the acquisition date. The closing share price of CAD 2.09 and closing USD/CAD currency exchange rate of 1.4193 on March 19, 
2025, were used as a basis for measuring the value of the consideration, as set forth below, and includes the Company’s previously held 50% 
interest in Meren Coop prior to March 19, 2025. 
Expressed in millions of United States dollars
Value of share consideration to BTG Oil & Gas 353.2
Value of previous interest held in Meren Coop 327.8
Total value of consideration 681.0
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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PAGE 64
Report to Shareholders  |  December 31, 2025
Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 13. Trade receivables are recognized 
at gross contractual amounts due, as they relate to large and credit-worthy customers. Historically, there has been no significant uncollectible 
trade receivables in Meren Coop.
The following table shows the initial purchase price allocation as included in the Company’s Report to Shareholders as per March 31, 2025, as 
well as the final purchase price allocation. The recognized amounts of assets and liabilities assumed as at the date of acquisition as reflected in 
the final purchase price allocation include some updates compared to the initial purchase price allocation based on new information regarding 
income taxes and information received from the operators related to site restoration provision, impacting the purchase price allocation as of 
the acquisition date and this final purchase price allocation is in line with the preliminary purchase price allocation as included in the Company’s 
Report to Shareholders as per June 30, 2025, and September 30, 2025. 
The recognized amounts of assets and liabilities assumed as at the date of acquisition were as follows:  
Final purchase price allocation
Initial purchase      
price allocation
Final purchase 
price allocation Variance
Assets acquired
Oil and gas properties 1,476.2 1,538.1 61.9 
Inventories 95.4 95.4 -
Indemnity asset (note 14) 21.6 21.6 -
Trade and other receivables 233.5 233.5 -
Cash and cash equivalents (1) 380.4 380.4 -
Total assets acquired 2,207.1 2,269.0 61.9
Liabilities assumed
Non-current financial liabilities 451.5 451.5 -
Non-current provisions 165.4 132.2 (33.2)
Deferred tax liabilities 343.3 374.3 31.0
Current financial liabilities 298.5 298.5 -
Trade and other payables 164.6 164.6 -
Current tax liabilities 48.2 112.3 64.1
Current provisions (note 14) 54.6 54.6 -
Total liabilities assumed 1,526.1 1,588.0 61.9
Net assets and liabilities recognized  681.0  681.0 -
Value of share consideration to BTG Oil & Gas 353.2 353.2 -
Value of previously held interest in Meren Coop (note 7) 327.8 327.8 -
Total value of consideration 681.0 681.0 -
(1) Cash and cash equivalents includes $59.1 million of cash held in the amalgamated company.
In the period from the acquisition date to December 31, 2025, the revenue and loss included in the Consolidated Statement of Net Income or 
Loss and Other Comprehensive Income or Loss relating to the acquired entities was $562.1 million and $53.7 million respectively. Acquisition-
related costs for the year ended December 31, 2024, and the year ended December 31, 2025, were included in general and administrative 
expenses and amounted to $6.9 million and $9.0 million, respectively. 
If the acquisition had taken place on January 1, 2025, the estimated revenue and loss of the combined Group for the year ended December 
31, 2025, would have been approximately $885.6 million and $82.7 million respectively. In determining these amounts, management assumed 
that no material fair value adjustments would have been required if the acquisition had occurred on January 1, 2025. These figures may not be 
indicative of the results that would have been achieved if the acquisition had actually taken place on January 1, 2025.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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PAGE 65
Report to Shareholders  |  December 31, 2025
5. Oil and gas properties:
Nigeria
Costs
At January 1, 2025 -
Acquired under amalgamation 1,538.1
Remeasurement of site restoration provisions 119.4
Additions 69.2
At December 31, 2025 1,726.7
Depletion and impairments
At January 1, 2025 -
Depletion (207.9)
Impairment charges (105.3)
At December 31, 2025 (313.2)
Oil and gas properties as at December 31, 2025 1,413.5
As at December 31, 2025, oil and gas properties amounted to $1,413.5 million and related to the licenses PML 52 (covering part of the Agbami 
field), PML 2 (Akpo field), PML 3 (Egina field) and PML 4 (Preowei Field) in Nigeria. Future development costs of $511.8 million were included in 
determination of the depletion expense for the year ended December 31, 2025.
The Company recognized a change in estimate of $119.4 million in oil and gas properties which related for $122.9 million to the remeasurement 
of the site restoration provisions acquired under the amalgamation in accordance with IAS 37 and for $3.5 million negative to the periodic re-
assessment of variables such as projected decommissioning cost per well, discount rates and economic lives of the fields (see note 14). 
The Company carries out impairment tests of individual cash-generating units when impairment triggers are identified. 
As at December 31, 2025, the Company determined that there was an indicator of impairment in respect of its oil and gas properties related to 
the Agbami field CGU, reflecting a more conservative oil price and cost outlook compared to prior assumptions. This assessment was driven by 
recent oil price volatility and updated cost forecasts. A significant portion of the revised cost outlook relates to planned long-term life-extension 
activities required to enable the Agbami FPSO to continue operating reliably and safely through the end of the current license period. The 
impairment does not reflect any adverse change in reservoir performance, reserves classification or the operational integrity of the Agbami field. 
The Company calculated the recoverable amount of the CGU using a fair value less costs to dispose discounted cash flow model. The recoverable 
amount was determined using discounted future after tax net cash flows of proved and probable oil and gas reserves using forecast prices and 
costs prepared by management’s expert at December 31, 2025.
It was determined that the carrying value exceeded the recoverable value of $298.0 million and non-cash impairment charges of $105.3 million 
were recognized on the Group’s oil and gas properties related to the CGU.
The applied discount rate has been determined to be in line with the discount rate applied on March 19, 2025, when the Company acquired its 
additional interest in Meren Coop.
Future commodity prices is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based 
on management’s estimates and available market data. Information about market prices in the near future can be derived from the futures 
contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions 
going forward. In assessing value in use, oil prices for the period up to 2036 are based on Brent prices as forecasted by Independent Qualified 
Reserve Engineers (IQRE) Analysis, ranging from $63/bbl to $86/bbl, and on management’s long-term price assumptions thereafter (2% 
inflation from 2036 onwards).
Operating and capital costs are calculated based on various technical assumptions, such as expected production profiles and the best estimate 
of the related cost. The long-term inflation rate is assumed to be 2%. 
A change in the future operating and capital costs by 5% would impact the impairment recognized by approximately $20.0 million. 
A change in the future oil price by 5% would impact the impairment recognized by approximately $22.0 million. 
A change in the discount rate by 1% would impact the impairment recognized by approximately $12.0 million. 
Actual outcomes may differ from these illustrative impairment sensitivities, as changes in individual assumptions are typically accompanied by 
management actions and adjustments to development and operating plans. 
Changes in input factors, either positive or negative would likely significantly change the actual impairment amount compared to the illustrative 
sensitivities above.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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PAGE 66
Report to Shareholders  |  December 31, 2025
Material contractual commitments 
In accordance with the terms of the production sharing contracts entered into by the Group along with other partners in respect of its oil 
fields and blocks, the Group has certain minimum exploration and development commitments with estimated capital expenditures in oil and 
gas properties of $0.3 billion as at December 31, 2025, $0.2 billion as at December 31, 2026, $0.1 billion as at December 31, 2027, and $0.1 
billion as at December 31, 2028.
6. Intangible exploration assets:
Intangible exploration assets
 Equatorial Guinea South  Africa Total
At January 1, 2024 13.4 5.7 19.1
Additions 4.5 5.7 10.2
At December 31, 2024 17.9 11.4 29.3
Additions 6.6 7.8 14.4
At December 31, 2025 24.5 19.2 43.7
As at December 31, 2025, the carrying amount of the Company’s intangible exploration assets in Equatorial Guinea was $24.5 million and 
related to its 80% interest in Blocks EG-18 and EG-31 (as at December 31, 2024 – $17.9 million). 
As at December 31, 2025, the carrying amount of the Company’s intangible exploration assets in South Africa was $19.2 million for its 18.0% 
(as at December 31, 2024 – 17.0%) participating interest in the Block 3B/4B Exploration Right (as at December 31, 2024 - $11.4 million).
On July 26, 2024, the Company signed an agreement with Eco to acquire an additional 1.0% interest in Block 3B/4B from Azinam Limited, Eco 
(Atlantic) Oil and Gas Ltd.’s (“Eco”) wholly owned subsidiary, in exchange for all common shares and warrants over common shares held by the 
Company in Eco. On January 13, 2025, the Company announced that it had completed this transaction. The Company’s interest in Block 3B/4B 
increased by 1.0% to 18.0% and the Company ceased to be a shareholder in Eco. The fair value of the Company’s investment in Eco on the day 
of the transaction was $8.0 million, which has been recorded as an addition to intangible exploration assets. 
As at December 31, 2025, no intangible exploration assets have been transferred to oil and gas properties as commercial reserves have not 
been established and technical feasibility for extraction has not been demonstrated.
7. Equity investment in joint venture:
Meren Coöperatief U.A (previously known as Prime Oil and Gas Coöperatief U.A.) (“Meren Coop”):
On March 19, 2025, the Company announced the completion of the amalgamation with BTG Oil & Gas (“the amalgamation) to consolidate the 
remaining 50% interest in Meren Coop in exchange for 239,828,655 common shares issued in Meren. Following completion of the amalgamation, 
Meren Coop is fully consolidated by the Company as from March 19, 2025 (see note 4).
The following table shows the Company’s carrying value of the non-controlling 50% interest in Meren Coop as at December 31, 2025, and 
December 31, 2024. The carrying value as per March 19, 2025, of $327.8 million has been assigned to the fair value of assets acquired and 
liabilities assumed as per note 4. 
 
December 31, 
2025
December 31, 
2024
Balance, beginning of the period 328.4 572.5
Share of joint venture profit 2.9 226.0
Distributions received from Meren Coop (60.0) (36.0)
Revaluation of contingent consideration 0.6 2.6
Reversal of impairment / (Impairment) 55.9 (436.7)
Impact of amalgamation (327.8) -
Balance, end of the period - 328.4
In the period up to and including March 19, 2025, the Company recognized an income of $2.9 million, relating to its investment in Meren Coop 
(year ended December 31, 2024 - $226.0 million). 
In the period up to and including March 19, 2025, Meren Coop made one distribution of $120.0 million gross, with a net payment to the Company 
of $60.0 million. In the year ended December 31, 2024, Meren Coop made one distribution of $72.0 million gross, with a net payment to the 
Company of $36.0 million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 76 =====

PAGE 67
Report to Shareholders  |  December 31, 2025
As at December 31, 2024, management determined there was an objective evidence of impairment in relation to the Company’s shareholding 
in Meren Coop as a result of the significant decrease in the Meren share price between June 24, 2024, when the Company announced the 
Proposed Reorganization and December 31, 2024. The fair value of the 50% shareholding in Meren Coop decreased as the fair value considers 
the number of Meren shares that were agreed in relation to the purchase of the additional interest in Meren Coop and the trading value 
of Meren shares, as this is an observable fair value input under IFRS Accounting Standards. As at December 31, 2024, the fair value of the 
Company’s existing shareholding in Meren Coop was calculated to be $328.4 million based on the implied value of the Proposed Reorganization, 
resulting in a non-cash impairment loss on the investment in Meren Coop of $436.7 million for the year ended December 31, 2024. As at March 
19, 2025, management determined there was an objective evidence of impairment reversal based on the Meren share price when the Company 
announced the completion of the amalgamation. The fair value of the 50% shareholding in Meren Coop was calculated to be $327.8 million, 
resulting in a non-cash impairment reversal on the investment in Meren Coop of $55.9 million for the three months ended March 31, 2025. 
The following tables summarizes Meren Coop’s financial information for the period up to and including March 19, 2025, and the year ended 
December 31, 2024. Following completion of the amalgamation on March 19, 2025, Meren Coop is fully consolidated by the Company.
Meren Coop’s Statement of Net Income and Comprehensive Income
Period ended Year ended
March 19,  
2025
December 31,  
2024 (1)
Revenue 323.5 782.7
Cost of Sales
Production costs (2) (187.4) (48.3)
Depletion costs (71.3) (372.0)
(258.7) (420.3)
Gross profit 64.8 362.4
Other operating income (3) - 329.7
General and administrative expenses (6.2) (28.2)
Operating profit 58.6 663.9
Finance income 2.4 6.4
Finance expense (4) (21.3) (97.8)
Net financial items (18.9) (91.4)
Profit before tax 39.7 572.5
Income tax (5) (34.0) (120.5)
Net income and comprehensive income for the period 5.7 452.0
Proportionate share of Meren Coop’s profit and comprehensive income for the period 2.9 226.0
Proportionate share of Meren Coop’s net income 2.9 226.0
(1) Certain comparative figures have been reclassified to conform with the presentation of the Company’s Consolidated Statement of Net Income or 
Loss and Other Comprehensive Income or Loss following completion of the amalgamation. 
(2) As at March 19, 2025, Meren Coop was in a lower net underlift position compared to December 31, 2024. This resulted in a loss of $133.1 million in 
the Statement of Net Income and Comprehensive Income for the period ended March 19, 2025 (year ended December 31, 2024 – profit of $171.2 
million) included in production costs.
(3) Other operating income in the year ended December 31, 2024, relates to the release of the previously recognized $305.3 million provision for the 
security deposit received from Equinor during 2021 and the recognition of an additional $24.4 million receivable pursuant to the Securitization 
Agreement.
(4) Finance expense is primarily made up of interest expenses incurred on external facilities and accretion expenses incurred on the decommissioning 
liability. Finance costs for the period ended March 19, 2025, also included a $3.7 million accounting loss on a purchased Asian put option and a zero-
premium Asian Dated Brent Collar (year ended December 31, 2024 – $7.1 million accounting loss on a purchased Asian Dated put options).
(5) In the period ended March 19, 2025, there is a tax charge of $34.0 million (year ended December 31, 2024 - $120.5 million). The tax charge is 
primarily made up of Corporate Income tax and Education tax, withholding tax on dividends of ten percent and deferred income tax. Other operating 
income of $329.7 million in the year ended December 31, 2024, was subject to ten percent Capital Gains Tax in Nigeria lowering the effective tax 
rate for the year.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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PAGE 68
Report to Shareholders  |  December 31, 2025
Supplementary information: Meren Coop’s Statement of Cash Flows 
Period ended Year ended
March 19,  
2025
December 31,  
2024 (1)
Cash flows generated by/ (used in)
Profit before tax 39.7 572.5
Adjustments for:
Depletion costs 71.3 372.0
Net financial items 18.9 91.4
Taxes (47.7) (201.4)
Change in provision for security deposit received - (305.3)
Other (1.0) 1.3
Cash generated from operating activities before working capital 81.2 530.5
Changes in working capital (8.2) 11.6
Net cash generated from operating activities 73.0 542.1
Expenditures on oil and gas properties (22.6) (152.5)
Interest income received 2.2 5.1
Net cash used in investing activities (20.4) (147.4)
Distributions paid to shareholders (120.0) (72.0)
Interest expense paid (10.8) (71.9)
Derivatives - (3.2)
Net cash used in financing activities (130.8) (147.1)
Foreign exchange variation on cash and cash equivalents - (0.3)
Total cash flow (78.2) 247.3
Cash and cash equivalents, beginning of the period 399.5 152.2
Cash and cash equivalents, end of the period 321.3 399.5
(1) Certain comparative figures have been reclassified to conform with the presentation of the Company’s Consolidated Statement of Cash Flows 
following completion of the amalgamation. 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 78 =====

PAGE 69
Report to Shareholders  |  December 31, 2025
8. Equity investments in associates:
The Company holds the following equity investments in associates:
Africa Energy 
Corp.
Eco (Atlantic) Oil 
and Gas Ltd
Impact Oil  
and Gas Ltd Total
Shares held at December 31, 2025 55,396,483 - 449,464,396
Ownership at December 31, 2025 11.6% - 39.5%
At January 1, 2024 24.8 7.6 102.3 134.7
Share of loss from equity investments (42.1) (0.6) (16.1) (58.8)
Reversal of impairment of equity investments 20.1 - - 20.1
Additional investments - - 88.6 88.6
Reclassification to Investment held for sale - (7.0) - (7.0)
At December 31, 2024 2.8 - 174.8 177.6
Share of loss from equity investments (0.4) - (2.5) (2.9)
Loss on dilution of equity investments (0.9) - - (0.9)
Distribution received - - (31.6) (31.6)
At December 31, 2025 1.5 - 140.7 142.2
In the year ended December 31, 2025, the Company recognized a loss of $3.8 million (year ended December 31, 2024 – loss of $38.7 million). 
The Company also recognized a gain of $0.9 million in the year ended December 31, 2025, on the shares in Eco (Atlantic) Oil and Gas Ltd 
classified as Investment held for sale, resulting in a total loss from investments in associates of $2.9 million in the year ended December 31, 
2025. 
As at December 31, 2025, the Company determined that there were no indicators of impairment for its investments in Africa Energy Corp. or 
Impact Oil and Gas Ltd.
A. Africa Energy Corp. (“Africa Energy”):
Africa Energy is an oil and gas exploration company with an interest in South Africa. 
As at December 31, 2025, the market value of the Company’s investment in Africa Energy was $4.5 million based on the share price of CAD 
0.11 (as at December 31, 2024 - $5.8 million). The carrying value is less than the market value from significant impairments recognized by 
Africa Energy. 
On March 31, 2025, Africa Energy announced the closing of a private placement of common shares, including the issue of common shares for 
debt. Meren did not participate in this private placement and as a result its shareholding in Africa Energy has been reduced from 19.7% as at 
December 31, 2024, to 11.6% as at December 31, 2025.
B. Eco (Atlantic) Oil and Gas Ltd. (“Eco”):
On July 26, 2024, the Company signed an agreement with Eco to acquire an additional 1.0% interest in Block 3B/4B from Azinam Limited, Eco’s 
wholly owned subsidiary, in exchange for all common shares and warrants over common shares held by the Company in Eco. Following the 
announcement of this transaction, the investment in Eco was reclassified to an investment held for sale (see note 10). On January 13, 2025, 
the Company announced the completion of this transaction.
C. Impact Oil and Gas Ltd (“Impact”):
Impact is an oil and gas exploration company with interests in Namibia and South Africa.
On January 10, 2024, the Company announced a strategic farmout agreement between its investee company Impact, and TotalEnergies, that 
allows the Company to continue its participation in the Venus oil development project and the follow-on exploration and appraisal campaign on 
Blocks 2913B and 2912 with no upfront costs. At the date hereof, Impact has a 9.5% interest in Blocks 2912 and 2913B that is fully carried 
for all joint venture costs, with no cap, through to first commercial production. This agreement provides Impact with a full interest-free carry 
loan over all of Impact’s remaining development, appraisal and exploration costs on the Blocks from January 1, 2024 (“Effective Date”), until the 
date on which Impact receives the first sales proceeds from oil production on the Blocks (“First Oil Date”). On and from the First Oil Date, the 
carry is repayable to TotalEnergies in kind from 60% of Impact’s after-tax cash flow, net of all joint venture costs, including capital expenditures. 
During the repayment of the carry, Impact will pool its entitlement barrels with those of TotalEnergies for more regular off-takes and a more 
stable cashflow profile and will also benefit from TotalEnergies’ marketing and sales capabilities.
On January 29, 2025, Impact distributed $31.6 million net to the Company’s shareholding.
The following tables summarize Impact’s financial information, based on a best estimate basis, for the year ended December 31, 2025, and 
December 31, 2024. The Company is not aware of any material changes to the financial information.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 79 =====

PAGE 70
Report to Shareholders  |  December 31, 2025
Balance Sheet
As at
December 31, 
2025
December 31, 
2024
Cash and cash equivalents included in current assets 40.7 125.1
Other current assets 0.4 1.7
Non-current assets (1) 317.1 316.5
Current liabilities (1.4) (0.8)
Non-current liabilities (0.6) -
Net assets of Impact 356.2 442.5
Percentage ownership 39.5 39.5
Proportionate share of Impact's net assets 140.7  174.8 
Statement of Net Loss and Comprehensive Loss from continuing operations
For the years ended
December 31, 
2025
December 31, 
2024
Net loss and comprehensive loss from continuing operations (6.3) (40.8)
Proportionate share of Impact’s loss (2.5) (16.1)
(1) As at December 31, 2025, the carrying value of non-current assets included a fair value adjustment of $190.0 million (as at December 31, 2024 - 
$96.4 million).
9. Inventories:
Inventories relate to well supplies and operational spare parts to be used in the oil production process in Nigeria. 
10. Investment held for sale:
On July 26, 2024, the Company signed an agreement with Eco to acquire an additional 1.0% interest in Block 3B/4B from Azinam Limited, Eco’s 
wholly owned subsidiary, in exchange for all common shares and warrants over common shares held by the Company in Eco. Following the 
announcement of this transaction, the investment in Eco was reclassified to an investment held for sale. On January 13, 2025, the Company 
announced the completion of this transaction with the result that the Company is no longer a shareholder in Eco. 
11. Trade and other receivables:
 
December 31, 
2025
December 31, 
2024
Trade receivables 5.6 -
Underlift position 12.2 -
Short-term receivables with partners 32.7 -
Prepaid expenses and accrued income 2.5 2.4
Other receivables 24.7 1.6
Total accounts receivable and prepaid expenses 77.7 4.0
 
The excess of product sold during the period over the participant’s ownership share of production is recognized by the Group as an underlift 
asset with a corresponding credit to production costs. An underlift receivable is the right to receive oil out of the Group’s equity share of future 
production.
The short-term receivables with partners mainly relate to the Group’s share in the receivables of its joint operations in Nigeria.
Other receivables include an indemnity asset of $21.6 million recognized under the deed of indemnity entered into between the Company and 
BTG Oil & Gas (see note 14).
As at December 31, 2025, and December 31, 2024, all receivables are due within one year and no provision for expected credit losses has been 
recognised.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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PAGE 71
Report to Shareholders  |  December 31, 2025
12. Cash and cash equivalents:
Cash and cash equivalents include short-term deposits made for varying periods of between one day and three months, depending on the 
immediate cash requirements of the Group, and earn interest at varying rates. 
13. Share capital:
A. The Company is authorized to issue an unlimited number of common shares with no par value.
B. Issued:
 December 31, 2025 December 31, 2024
 Shares Amount  Shares Amount
Balance, beginning of the period 439,078,170 1,195.8 463,831,871 1,265.3
Share issuance to BTG Oil & Gas under amalgamation 
Agreement 239,828,655 353.2 - -
Exercise of Share Options 367,600 0.4      647,000 0.5
Settlement of Restricted Share Units 836,323 1.1 271,063 0.5
Settlement of Performance Share Units 1,974,498 2.5 577,968 1.1
Cancellation of shares repurchased (6,176,053) (16.8) (26,249,732) (71.6)
Balance, end of the period 675,909,193 1,536.2 439,078,170 1,195.8
 
The Company launched a share buyback program on December 6, 2024, that ended on December 5, 2025, under which 2.5 million Meren 
common shares were repurchased during the year ended December 31, 2024, of which 2.2 million Meren common shares were cancelled during 
the year ended December 31, 2024. In the three months ended March 31, 2025, a total of 5.9 million Meren common shares were repurchased 
and 6.2 million Meren common shares were cancelled during the three months ended March 31, 2025. Following March 31, 2025, no further 
shares were purchased in the period to December 31, 2025. The Company launched a new share buyback program on December 8, 2025, under 
which no Meren common shares have been repurchased during 2025. 
The balance of share capital has been reduced by determining the average per-share amounts in the share capital account, before cancellation 
of shares repurchased, and applying this to the numbers of shares cancelled. The difference between the reduction in share capital and the 
amount paid for shares repurchased has been added to the balance of contributed surplus.
In the year ended December 31, 2025, the Board of Directors approved and paid four dividends of $0.0371 per share for a total amount of 
$100.2 million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 81 =====

PAGE 72
Report to Shareholders  |  December 31, 2025
14. Provisions:
 
Site  
restoration
Contingent 
consideration
Share-based 
compensation Others Total
At January 1, 2024 5.5 37.8 14.1 - 57.4
Charges - - 1.5 - 1.5
Unwinding of discount 0.2 2.6 - - 2.8
Settlements - - (8.3) - (8.3)
At December 31, 2024 5.7 40.4 7.3 - 53.4
Acquired under amalgamation 129.4 54.6 - 2.8 186.8
Changes in estimates 119.4 - - - 119.4
Charges - - 6.3 1.4 7.7
Unwinding of discount 9.2 2.9 - - 12.1
Settlements - - (8.3) - (8.3)
At December 31, 2025 263.7 97.9 5.3 4.2 371.1
Non-current 5.7 40.4 3.1 - 49.2
Current - - 4.2 - 4.2
At December 31, 2024 5.7 40.4 7.3 - 53.4
Non-current 263.7 - 3.4 4.2 271.3
Current - 97.9 1.9 - 99.8
At December 31, 2025 263.7 97.9 5.3 4.2 371.1
A. Site restoration
The provision for site restoration amounted to $263.7 million as per December 31, 2025 (as at December 31, 2024 - $5.7 million). The fair 
value of the provision for site restoration mainly relates to Nigeria and was based on the estimated future cash flows to decommission the oil 
and gas properties at the end of their useful life. The discount rate used to determine the net present value of the decommissioning obligation 
was 4.8% (as at December 31, 2024 – 3.5%) based on a risk-free rate with a similar maturity to that of the timing of the expected cash flows 
and a long-term inflation rate of 2.3% (as at December 31, 2024 – 2%). 
The site restoration provisions acquired under the amalgamation represents the present value of decommissioning costs relating to the acquired 
oil and gas properties, which are expected to be incurred up to the economic cut-off dates of the Agbami, Akpo and Egina fields. These provisions 
have been calculated based on the cash flow estimates as provided by the operators of the fields. The fair value of the site restoration 
provisions acquired on amalgamation totalling $129.4 million have been calculated using a credit-adjusted discount rate in accordance with IFRS 
3, which has subsequently been re-measured using a risk-free rate in accordance with IAS 37 resulting in a change in estimate of $122.9 million.
The undiscounted costs at December 31, 2025, are estimated to be approximately $0.6 billion, net to the Company, and include the costs of 
physical well abandonment and site remediation. The costs are expected to be incurred up to the economic cut-off dates of the Agbami, Akpo 
and Egina fields, ranging from 2043 to 2044, which is when the producing oil and gas properties are expected to cease operations. In the year 
ended December 31, 2025, the Group revised its provision for decommissioning liabilities downwards by $3.5 million resulting from periodic 
re-assessment of projected decommissioning cost per well, discount rates and economic lives of the fields.  
An increase in the inflation rate by 1% would increase the site restoration provision recognized by approximately $53.1 million. 
A decrease in the discount rate of 1% would increase the site restoration provision recognized by approximately $49.3 million.
B. Contingent consideration 
Under the Meren Coop Sale and Purchase Agreement completed on January 14, 2020, a deferred payment of $118.0 million, subject to 
adjustment, may be due to the seller contingent upon the timing of the final PML 52 tract participation in the Agbami field. The signing 
of the Securitization Agreement by Meren Coop in 2021 led to the Company reassessing its view of the likelihood of making a contingent 
consideration payment to the seller. The signing of the Securitization Agreement by Meren Coop does not constitute a redetermination of the 
tract participation and therefore does not trigger the payment of a contingent consideration under the Sale and Purchase Agreement but, at 
the Company’s discretion, could trigger discussions with the seller. The outcome of this process is uncertain. In 2021, the Company recorded 
$32.0 million as contingent consideration and increased this to $40.4 million as at December 31, 2024, and to $43.4 million in the year ended 
December 31, 2025. The deferred payment is expected to be due in the three months ended March 31, 2026, and has therefore been presented 
as a short term provision as per December 31, 2025.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 82 =====

PAGE 73
Report to Shareholders  |  December 31, 2025
On June 25, 2021, Meren Nigeria 52 Limited (previously named Prime 127 Nigeria Limited) (“Meren 52”), a subsidiary of Meren Coop, signed a 
securitization agreement with two of the unit parties, Equinor and Chevron (the “Securitization Agreement”), whereby Equinor agreed to pay 
a security deposit to the two other JV parties to secure future payments due under that Securitization Agreement, pending a comprehensive 
resolution being reached among all unit parties in respect of the tract participation in the Agbami field by December 27, 2024. In accordance 
with the Securitization Agreement, on June 29, 2021, Meren 52 received from Equinor its portion of the security deposit in the form of a cash 
payment of $305.3 million. Meren 52 received an additional payment of $24.4 million on January 31, 2025, pursuant to the Securitization 
Agreement. Given no comprehensive resolution was reached by December 27, 2024, Meren 52 has recognized its portion of the security 
deposit and the additional receivable under the Securitization Agreement as other operating income on December 27, 2024. The process of 
implementing a new tract participation by the parties is ongoing and is subject to government approval. The parties will continue discussions to 
seek final resolution of the formal redetermination of the Agbami tract participation in respect of the period after December 27, 2024, however 
there is no certainty that such ongoing discussions will result in a final resolution. 
Under the amended joint sale agreement between (among others) BTG Holding and the seller dated October 31, 2018, the seller could 
potentially claim that, given an additional payment has been received under the securitization agreement, this triggers a payment obligation 
of $54.6 million, exclusive of interest, capital taxes and certain deductions, contingent upon various criteria, with the outcome of this potential 
claim uncertain. Management considers the likelihood of any interest being payable to be unlikely. The Company has recorded an indemnity 
asset of $21.6 million under the deed of indemnity entered into between a subsidiary of the Company and BTG Oil & Gas on February 19, 2025, 
for any costs suffered or incurred above $33.0 million post completion of the amalgamation, with the deed of indemnity backed by a $22.0 
million letter of credit granted in favour a subsidiary of the Company. The letter of credit will remain in place for an initial period of two years 
and if a claim is not resolved in two years or is made after the two year period BTG Oil & Gas has undertaken to extend or reinstate the letter 
of credit. 
15. Financial liabilities: 
 
Reserves Based  
Lending Facility Lease Liability Total
At January 1, 2024 - - -
Initial recognition of IFRS 16 lease liability - 3.7 3.7
Repayments - (0.4) (0.4)
At December 31, 2024 - 3.3 3.3
Acquired under amalgamation 750.0 - 750.0
Initial recognition of IFRS 16 lease liability - 1.1 1.1
Repayments (420.0) (0.6) (420.6)
At December 31, 2025 330.0 3.8 333.8
Non-current - 2.6 2.6
Current - 0.7 0.7
At December 31, 2024 - 3.3 3.3
Non-current 262.3 2.9 265.2
Current 67.7 0.9 68.6
At December 31, 2025 330.0 3.8 333.8
A. Reserves Based Lending Facility
On amalgamation the Company acquired a Reserves Based Lending Facility (“RBL”) of $800.0 million of which $750.0 million was drawn. On 
October 28, 2025, the Company voluntarily cancelled $100.0 million of its RBL commitments resulting in a remaining total commitment 
of $700.0 million. The total amount that can be drawn under the RBL is limited to the Borrowing Base Amount (“BBA”), which is subject to 
redeterminations on March 31 and September 30 of each year, limited by aggregate commitments. As of December 31, 2025, the BBA was 
$468.4 million, which will amortize as the RBL moves towards final maturity. The RBL matures on June 20, 2029, but amortizes each quarter 
as per the lower of commitments and the BBA.
The principal bore interest at Term SOFR + 4.00% until June 2025 and bears interest of Term SOFR + 4.25% until June 2027, then Term SOFR 
+ 4.50% until final maturity on June 20, 2029. In addition, commitment fees of 40% of the margin are payable on the undrawn but available 
portion of the RBL, and commitment fees of 20% of the margin are payable on the unavailable portion of the RBL. 
The RBL perimeter remains at the Meren Coop level - Meren Coop is the borrower, and Meren 52 Nigeria Limited and Meren 234 Nigeria Limited 
(previously named Prime 130 Nigeria Limited) (“Meren 234”) are the guarantors. The main security package is comprised of security over the 
shares, production assets, contracts and rights of the Nigerian entities - Meren 52 and Meren 234. In addition, RBL lenders have security over 
cash and cash equivalents held in project accounts, receivables against cargos sold and all relevant insurance policies of the three entities. 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 83 =====

PAGE 74
Report to Shareholders  |  December 31, 2025
All financial and liquidity covenants covered by the RBL are restricted to these three entities. The Meren Coop entities shall ensure that total net 
debt to adjusted EBITDAX on each quarter is no greater than 3.0:1, that the historic debt service cover ratio for the preceding year is greater 
than 1.20:1, and that on each quarter of each year during each of the four successive quarters there are or will be sufficient funds available to 
the group to meet all relevant expenditure to be incurred in each of these four successive quarters as they fall due. The Company has been in 
compliance with the covenants in the year ended December 31, 2025. 
In the event that the BBA reduces to an amount below the outstanding RBL balance, the Company would be required to repay the difference 
immediately.
B. Corporate Facility
On May 22, 2025, the Company cancelled its $65.0 million Corporate Facility. 
16. Trade and other payables:
 
December 31, 
2025
December 31, 
2024
Short-term payables with partners 97.9 -
Crude oil overlift payable 26.1 -
Accruals 24.0 7.7
Other payables 2.8 2.0
Total trade and other payables 150.8 9.7
The short-term payables with partners mainly relate to the Group’s share in the payables of its joint operations in Nigeria.
The Group’s excess of crude oil purchased during the year over its entitlement share of production, is recognized as a crude oil overlift payable 
balance with a corresponding charge to cost of sales. An overlift liability is the obligation to deliver oil out of the Group’s equity share of future 
production. 
All trade and other payables are due within one year. 
17. Commitments and contingencies:
A. Contingent consideration:
For information on the contingent consideration in relation to the historical acquisition of Meren Coop, refer to Note 14B. 
B. Withdrawal from Kenya:
On May 23, 2023, the Kenya entities along with TotalEnergies submitted withdrawal notices to the remaining joint venture party on Blocks 
10BB, 13T and 10BA in Kenya, to unconditionally and irrevocably, withdraw from the entirety of the JOAs and PSCs for these concessions. The 
Company concurrently submitted notices to Ministry of Energy and Petroleum, requesting the government’s consent to transfer all of its rights 
and future obligations under the PSCs to its remaining joint venture party. Government consent to the transfer was received on September 
18, 2025, and the Company subsequently transferred all of its rights and future obligation of Blocks 10BB, 13T and 10BA to its remaining joint 
venture party with effect on and from June 30, 2023. In accordance with the JOA and PSC the Company retains economic participation for 
activities prior to June 30, 2023, which might result in additional costs for the Company. The Company continues to monitor the claim made 
against the operator by local communities in relation to past operations which may relate to the period prior to June 30, 2023. No provision has 
been recognized for this as at December 31, 2025. 
C. Securities and guarantees
Under the conditions of the RBL facility, the main security package is comprised of security over the shares, production assets, contracts and 
rights of the Nigerian entities Meren 52 and Meren 234, cash and cash equivalents in the amount of $152.9 million as per December 31, 2025, 
that are held within the project accounts in Nigeria and The Netherlands, proceeds from the oil cargos sold and proceeds from the intercompany 
receivables between the Company and the Nigerian entities. Further, any and all claims relating to, and all returns of premium in respect of, all 
relevant insurance policies have been secured.
D. Commitments from forward sales
The Group uses a mix of financial derivatives and physical forward sales contracts to manage its commodity price risk and ensure stability in 
cash flows. Its strategy is to hedge between 70-100% of its post-tax net entitlement production for the next 12-months. As at December 31, 
2025, two cargos of the Group’s expected lifted entitlement production for 2026 are covered by forward contracts. The average cargo lifted is 
for 1 million barrels of oil. The Group’s triggers for these two cargos covered by forward contracts have been triggered at an average of $62.1 
per barrel.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 84 =====

PAGE 75
Report to Shareholders  |  December 31, 2025
18. Segment information:
The Group operates within several geographical areas. All revenue and therefore gross profit as reported by the Company is currently derived 
from operations in Nigeria. 
For segment information about oil and gas properties and intangible exploration assets, see note 5 and 6.
19. Net Revenue:
Revenue for the years ended December 31, 2025, and December 31, 2024, is comprised of the following:              
For the years ended  
December 31, 
2025
December 31, 
2024
Oil revenue 545.5 -
Gas revenue 14.4 -
Total net revenue 559.9 -
In the year ended December 31, 2025, total revenue amounted to $559.9 million (year ended December 31, 2025 - nil), of which $545.5 million 
related to the Group’s sales of crude oil to customers. Under the conditions of the Offtake Agreement, an aggregate of at least 90% of the 
Group’s cargos is required to be delivered to one of the lenders.
In the year ended December 31, 2025, the Group was allocated 8 oil liftings, with a total sales volume of 8 million barrels at an average realized 
oil price of USD $68.2/bbl. 
Prior to March 19, 2025, the Company equity accounted for its investment in Meren Coop and therefore no revenue has been reported before 
this date. See note 7 for further details.
20. Production costs:
Production costs for the years ended December 31, 2025, and December 31, 2024, is comprised of the following:
For the years ended  
December 31, 
2025
December 31, 
2024
Cost of operations 114.3 -
Royalties 29.4 -
Others 22.9 -
Total production costs 166.6 -
 
Cost of operations mainly relate to lifting costs from personnel, material and services from third parties. 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 85 =====

PAGE 76
Report to Shareholders  |  December 31, 2025
21. Share based compensation:
In the year ended December 31, 2025, the Company recognized a total of $6.3 million in share-based compensation expense relating to the 
Long-Term Incentive Plan (“LTIP”) and Stock Option Plan (year ended December 31, 2024 – $1.5 million). 
A. Share purchase options:
At the 2016 Annual General and Special Meeting the Company’s shareholders approved the terms of the stock option plan (the “Stock Option 
Plan”).  The Stock Option Plan provided that the aggregate number of Common Shares which could be reserved for issuance as incentive share 
purchase options could not exceed 3.5% of the Common Shares outstanding, and option exercise prices would reflect current trading values of 
the Company’s shares.  The term of any option granted under the Stock Option Plan was fixed by the Board of Directors and could not exceed 
five years from the date of grant. The Company ceased awarding share purchase options under the Stock Option Plan in 2021 and did not issue 
any share purchase options between 2022 and 2025.  Instead, the Company now awards PSUs to executives and staff under the Company’s 
LTIP.  Refer to note 21B for further information on the Company’s PSUs.  
The Company’s outstanding share purchase options are as follows:
December 31, 2025 December 31, 2024
 
Number of 
options
Weighted 
average 
exercise price 
(CAD$)
Number of 
options
Weighted average 
exercise price 
(CAD$)
Outstanding, beginning of the year 457,616 1.23 1,104,616 1.20
Forfeited - - - -
Exercised (435,000) 1.21 (647,000) 1.17
Balance, end of the year 22,616 1.61 457,616 1.23
 
 
The following table summarizes information regarding the Company’s share purchase options outstanding and exercisable at December 31, 
2025:
Weighted Average Exercise price 
(CAD$/share) Number outstanding Number exercisable
 Weighted average remaining 
contractual life in years
1.61 22,616 22,616 0.63
In the year ended December 31, 2025, the Company did not recognize a share based payment expense (year ended December 31, 2024 - nil), 
related to share purchase options.
B. Performance share units (“PSUs”):
On April 19, 2016, the shareholders of the Company approved a new long term incentive plan which was subsequently amended and restated 
following shareholder approval on April 20, 2022. Under the terms of the LTIP, eligible plan participants may be granted PSUs and RSUs. The 
LTIP provides that an aggregate number of Common Shares which may be reserved for issuance in respect of grants of RSUs and PSUs shall not 
exceed 28,256,682 shares, which represents approximately 4% of the issued and outstanding Common Shares of the Company as at December 
31, 2025.  PSUs are notional share instruments which track the value of the Common Shares and are subject to non-market performance 
conditions related to key strategic, financial and operational milestones. PSUs cliff vest three years from the date of grant, at which time the 
Board of Directors will assign a performance multiple ranging from nil to 200% to determine the ultimate vested number of PSUs. PSUs are 
awarded to executives and from 2022 are awarded to staff, replacing share options.  They may be settled in shares issued from treasury or 
cash, at the discretion of the Board of Directors.  
The Company’s PSUs outstanding are as follows:
December 31,  
2025
December 31,  
2024
 Number of PSUs Number of PSUs
Outstanding, beginning of the year 7,609,689 7,122,839
Granted 6,242,388 3,968,993
Forfeited (811,168) -
Vested (4,445,461) (3,482,143)
Balance, end of the year 8,595,448 7,609,689
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 86 =====

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Report to Shareholders  |  December 31, 2025
In the year ended December 31, 2025, 4,445,461 PSUs vested in which 2,471,228 PSUs were settled for a cash payment of $3.8 million and 
the remaining were settled via the issuance of Common Shares of the Company (year ended December 31, 2024 - $5.3 million). 
The Company accounts for PSUs as share-based awards whereby the estimated fair value of the grant is expensive throughout the remaining 
vesting period. In the year ended December 31, 2025, the Company recognized $4.9 million in share-based compensation expenses relating to 
the PSUs (year ended December 31, 2024 - $0.9 million) with the increase mainly caused by accelerated charges and changes in the expected 
outcome of performance multiples. 
C. Restricted share units (“RSUs”):
RSUs granted to Non-Executive Directors cliff vest three years from the date of grant. The estimated fair value of RSUs are expensed evenly 
throughout the remaining vesting period. RSUs are no longer awarded to executives, and only PSU’s are awarded. RSUs may be settled in shares 
issued from treasury or cash, at the discretion of the Board of Directors.
The Company’s RSUs outstanding are as follows:
December 31,  
2025
December 31,  
2024
 Number of RSUs Number of RSUs
Outstanding, beginning of the year 1,174,553 1,278,318
Granted 969,068 541,621
Vested (1,383,688) (645,386)
Balance, end of the year 759,933 1,174,553
In the year ended December 31, 2025, 1,383,688 RSUs vested with 547,365 being settled for a cash payment of $0.8 million and the remaining 
were settled via the issuance of Common Shares of the Company (year ended December 31, 2024 - $0.6 million). 
The Company accounts for RSUs as share-based awards whereby the estimated fair value of the grant is expensed evenly throughout the 
remaining vesting period. In the year ended December 31, 2025, the Company recognized $1.4 million in share-based compensation relating to 
the RSUs (year ended December 31, 2024 - $0.6 million) with the increase mainly caused by accelerated charges.  
22. Finance income: 
For the years ended  
December 31, 
2025
December 31, 
2024
Interest income on cash and cash equivalents 3.9 7.1
Interest income from associated companies 0.2 0.5
Total finance income 4.1 7.6
23. Finance expense:
For the years ended  
December 31, 
2025
December 31, 
2024
Interest expense on RBL 30.4 -
Commitment fees 4.3 3.4
Unwinding of site restoration provision 9.2 0.2
Others 3.9 1.3
Total finance expense 47.8 4.9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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PAGE 78
Report to Shareholders  |  December 31, 2025
24. Income tax:
For the years ended  
December 31, 
2025
December 31, 
2024
Current tax expense 135.9 -
Deferred tax income (92.5) -
Total income tax 43.4 -
The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the tax rate of Canada as follows:
The tax rate consists of the combined federal and provincial statutory tax rates for the Company for the years ended December 31, 2025, 
and December 31, 2024. The differences between the actual income tax expense and the expected Canadian federal and provincial statutory 
corporate income tax expense/ (recovery) related to the withholding tax on distributed dividends, education tax in Nigeria, income from result 
in Joint Venture that is not taxable and non taxable expense from over/underlift movements. 
For the years ended  
December 31, 
2025
December 31, 
2024
Net profit/ (loss) and comprehensive profit/ (loss) 11.8 (279.1)
Combined federal and provincial statutory income tax rate 27.0% 27.0%
Expected expense/ (recovery) 3.2 (75.4)
Foreign rate differences 0.6 0.1
Expenses not deductible for tax purposes 9.0 0.4
Creation of unrecorded tax losses 12.1 7.4
Non-deductible withholding tax on dividend 18.5 -
Education tax and Naseni fee 15.1 -
Equity earnings (15.1) (48.9)
Tax charge 43.4 -
The Company has estimated non-capital losses carried forward of $180.1 million in Canada which expire from 2026 through 2045. The 
Company has estimated capital losses carried forward of $12.9 million in Canada. The Company has estimated deductible temporary differences 
of $114.1 million in Canada. 
At December 31, 2025, the Group has estimated losses carried forward of $1.3 billion that are indefinitely available for offsetting against future 
taxable profits in The Netherlands. 
At December 31, 2025, resulting from the absence of projected taxable profits in the near foreseeable future in both Canada and The 
Netherlands, the Company did not recognize a deferred tax asset (as at December 31, 2024 - nil). 
Specification of deferred tax assets and tax liabilities
As at  
Accelerated  
allowances
At January 1, 2025 -
Acquired under amalgamation 374.3
Deferred tax credit (92.5)
At December 31, 2025 281.8
As at  
December 31, 
2025
December 31, 
2024
Deferred tax assets 
Temporary differences 5.4 -
5.4 -
Deferred tax liabilities 
Accelerated allowances 287.2 -
287.2 -
Total deferred tax 281.8 -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

===== SIDA 88 =====