FULLTEXT DEL 1 AV 3
Kvartalsrapport Q4 2025
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Suite 2500
666 Burrard Street,
Vancouver, B.C. Canada V6C 2X8
info@mereninc.com
mereninc.com
* All dollar amounts in this press release are U.S. Dollars unless otherwise indicated.
NEWS RELEASE
MEREN ANNOUNCES 2025 FOURTH QUARTER AND FULL-YEAR
RESULTS, ITS YEAR-END 2025 STATEMENT OF RESERVES AND
FIRST QUARTERLY DIVIDEND OF 2026
February 24, 2026 (MER–TSX, MER–Nasdaq-Stockholm, MRNFF–OTCQX) – Meren Energy Inc.
(“Meren” or the “Company”) today published its financial and operating results for the three months and
the year ended December 31, 2025, and posted its 2025 statement of reserves on SEDAR +
(www.sedarplus.ca) as part of its Annual Information Form. Meren is also pleased to declare its first
quarterly distribution in 2026 of approximately $25.1 million under its base dividend policy.
Meren President and CEO, Oliver Quinn commented: “2025 was a strong year of delivery for Meren.
We closed the transformational Prime consolidation, delivered strong shareholder returns , and
strengthened the balance sheet through disciplined deleveraging. These actions have reshaped the
company into a simpler, more resilient business that can deliver value through the cycle. As we enter
2026, our priority is consistent execution with a focus on converting our high -quality organic growth
opportunities into long term value drivers and returns, whilst maintaining capital discipline and a healthy
balance sheet.”
Highlights*
• During 2025, closed the transformative Prime amalgamation to take full control of Prime’s
assets, doubling Meren’s reserves and production;
• Distributed approximately $100 million to the Company’s shareholders under the base dividend
policy and repurchased 5.9 million shares at a cost of approximately $8 million;
• Achieved average daily W.I .1 and entitlement2 production of 30,800 boepd and 35,100 boepd,
respectively, for 2025, in line with the revised full-year management guidance;
• Sold three cargos in Q4 2025 at an average sales price of $64.4/bbl and twelve cargos in 2025
at an average sales price of $72.2/bbl, both of which were higher than average Dated Brent for
the same periods;
• In 2025 reduced the RBL by $420.0 million, reducing interest expenses and ending 2025 with
a debt balance of $330.0 million;
• End of 2025 cash balance of $174.7 million resulting in a net debt position of $155.3 million
with a Net Debt/ EBITDAX 3 of 0.4x as at December 31, 2025, with RBL facility headroom of
$138.4 million.
• During 2025:
o EBITDAX3 of $440.7 million;
o Cashflow from operations3,4 before working capital adjustment of $261.8 million; and
o Cash capital investments of $100.2 million.
• Reported net loss of $31.6 million ($0.05/share) for full -year 2025, primarily from a non -cash
impairment of $105.3 million for the Agbami cash generating unit (“CGU”) reflecting a more
conservative oil price and cost outlook compared to prior assumptions;
• Following continued strong operating performance and after consideration of organic
investment requirements and balance sheet resilience, the Board has declared the first
quarterly dividend in 2026 of approximately $25.1 million; and
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• On February 2, 2026, the Company announced that Roger Tucker had stepped down from the
role of President and CEO and as a director of Meren, and that Oliver Quinn had been
appointed as his successor and joined the Board as director.
• Meren’s year-end 2025 reserves5:
o YE’25 reserves determination has delivered after -tax 1P NPV(10) and 2P NPV(10)
valuations of $588 million (YE’24: $ 1,248 million) and $1,499 million (YE’24: $ 2,128
million) respectively6.
o YE’25 W.I. and net entitlement7 1P reserves of 48.8 MMboe (YE’24: 59.8 MMboe) and
62.5 MMboe (YE’24: 70.8 MMboe), respectively.
o YE’25 W.I. and net entitlement 2P reserves of 87.7 MMboe (YE’24: 101.6 MMboe) and
107.4 MMboe (YE’24: 116.4 MMboe), respectively.
o YE’25 aggregate W.I. 2P reserves and 2C contingent resources of 140.2 MMboe
(YE’24: 129.6 MMboe).
2025 Fourth Quarter Results Highlights
Three months ended Twelve months ended
Meren Highlights i,ii Unit December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
Net (loss) / income $’m (90.8) 6.2 (31.6) (279.1)
Net (loss)/ income per
share – basic iii
$/
share (0.13) 0.02 (0.05) (0.62)
Net debt position iv $’m 155.3 289.1 155.3 289.1
WI production iv boepd 28,100 34,400 30,800 34,000
Entitlement
production iv boepd 31,500 39,000 35,100 38,800
Cash flow from
operations v,vi $’m 18.7 n/a 261.8 n/a
EBITDAX v $’m 72.7 n/a 440.7 n/a
Capital investments v $’m 19.8 n/a 100.2 n/a
Notes:
i. The financial information in this table was selected from the Company’s audited consolidated financial statements for the year ended December 31, 2025. The
Company's consolidated financial statements, notes to the financial statements, management's discussion and analysis for the year ended December 31,
2025 and 2024 and the 2025 Report to Shareholders and Annual Information Form have been filed on SEDAR+ (www.sedarplus.ca) and are available on the
Company’s website (www.mereninc.com).
ii. The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on pages 14-17 of the 2025 Shareholder
Report.
iii. Based on the weighted average number of shares outstanding for the three months and year ended December 31, 2025, of 675,685, 556 and 624,464,015
respectively, which accounts for the newly issued shares to BTG Oil & Gas on March 19, 2025.
iv. Net debt position and production numbers as presented for the comparative periods includes 100 percent of Meren Coöperatief U.A. (previously known as
Prime Oil & Gas Coöperatief U.A) to be comparable with net debt position and production numbers for the three months and year ended December 31, 2025.
v. Highlights are reported for the year 2025 only, on a constructed financial information basis, see pages 10-12 of the 2025 Shareholder Report for further
information.
vi. Cash flow from operations before working capital and interest payments.
In 2025, the Company recorded revenue, mainly related to oil sales, following the amalgamation with
Meren Coöperatief U.A. (previously known as Prime Oil & Gas Coöperatief U.A) (“Meren Coop”). In
2024 and 2023, the Company held a 50% investment in Meren Coop, accounted for as a Joint Venture
and therefore no revenue was recognized in these years.
In 2025, the Company recorded a net loss attributable to common shareholders of $31.6 million ( 2024:
net loss of $279.1 million).
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As at December 31, 2025, the Company determined that there was an indicator of impairment of $105.3
million in respect of its oil and gas properties related to the Agbami field cash generating unit (“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. These activities are also expected to enhance the flexibility of the Agbami FPSO
to support future infill drilling and potential nearby tie -in opportunities, consistent with the Company’s
long-term organic growth strategy. Such potential upside relates to contingent resources which are not
included in the recoverable amount of the CGU for impairment testing purposes. The impairment does
not reflect any adverse change in reservoir performance, reserves classification or the operational
integrity of the Agbami field.
Please refer to the 2025 Shareholder Report for further details on the 2025 and comparative 2024
periods.
Year-End 2025 Statement of Reserves
The Company has posted its 202 5 statement of reserves on SEDAR + (www.sedarplus.ca) as part of
its Annual Information Form. This disclosure is based on an independent reserves evaluation, effective
January 1, 202 6, prepared by RISC (UK) Limited (“RISC”) for Meren in accordance with Canadian
National Instrument 51-101 – Standards for Oil and Gas Activities ("NI 51 -101") and the Canadian Oil
and Gas Evaluation Handbook ("COGE Handbook").
Meren’s main assets are an indirect 8% interest in Petroleum Mining License (“PML”) 52 and an indirect
16% interest in PMLs 2, 3, 4; these are deep-water Nigeria concessions. PML 52 is operated by affiliates
of Chevron Corporation and contains the producing Agbami field. PML 2, PML 3 and PML 4 are
operated by affiliates of TotalEnergies SE and contain the producing Akpo and Egina fields.
The year -end 202 5 reserves and reconciliation of changes in W.I. reserves are summarized in the
following tables:
Summary of Oil and Gas Reserves (Forecast Prices and Costs)
Light and Medium Oil Natural Gas Oil Equivalent
Reserve Category Gross
(MMstb)
Net
(MMstb)
Gross
(Bscf)
Net
(Bscf)
Gross
(MMboe)
Net
(MMboe)
Proved
Developed Producing 20.2 29.1 52.0 52.0 28.8 37.8
Developed Non-Producing - - - - - -
Undeveloped 18.3 23.1 10.0 10.0 20.0 24.8
Total Proved 38.4 52.2 62.0 62.0 48.8 62.5
Probable 30.7 36.6 49.7 49.7 39.0 44.9
Total Proved plus Probable 69.1 88.8 111.7 111.7 87.7 107.4
Possible 23.7 25.4 51.9 51.9 32.4 34.0
Total Proved plus Probable
plus Possible 92.8 114.2 163.6 163.6 120.1 141.4
Notes:
i. The figures in the table may not add up precisely due to rounding.
ii. Units are MMstb (million stock tank barrels) and Bscf (billion standard cubic feet).
iii. Oil equivalent values are based on volumes Barrel of Oil Equivalent (BOE): 6 Mcf = 1 BOE. BOEs may be misleading
particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
iv. Gross Company Reserves are the total project sales volumes multiplied by Meren’s working interest.
v. Net oil Reserves are Meren’s net entitlement calculated using economic limit testing.
vi. Gross and net Reserves for sales gas are equal as the gas terms are set out in the Gas Sales and Purchase
Agreement, rather than the PSA, and the net Reserves are based on Meren’s working interest.
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Gross Light and Medium Oil (MMstb) Conventional Natural Gas (Bscf)
Proved Probable Proved +
Probable Proved Probable Proved +
Probable
Effective date: 31
December 2025 44.8 34.1 78.9 89.8 46.0 135.8
Extensions and
Improved Recovery 0.0 0.0 0.0 0.0 0.0 0.0
Resource Transfers -0.9 -0.5 -1.4 -1.9 -1.2 -3.1
Technical Revisions 2.5 -2.9 -0.4 -6.2 4.9 -1.3
Discoveries 0.0 0.0 0.0 0.0 0.0 0.0
Acquisitions 0.0 0.0 0.0 0.0 0.0 0.0
Dispositions 0.0 0.0 0.0 0.0 0.0 0.0
Economic Factors 0.0 0.0 0.0 0.0 0.0 0.0
Production 8.0 0.0 8.0 19.7 0.0 19.7
Effective date: 1
January 2026 38.4 30.7 69.1 62.0 49.7 111.7
Notes:
i. The figures in the table may not add up precisely due to rounding.
ii. Gross Company Reserves are the total project sales volumes multiplied by Meren’s working interest.
Outlook
Nigeria
Nigeria’s macroeconomic and sector-specific reforms are beginning to show tangible results, with improved
fiscal clarity, stronger government engagement, and targeted incentives aimed at sustaining investment in
the oil and gas sector. The Federal Government has reaffirmed its support for upstream development through
regulatory stability and commercial incentives, contributing to renewed capital commitment across offshore
oil and gas projects. This improved investment climate is evidenced by recent final in vestment decisions on
major developments such as Bonga North, Ubeta Gas Project, and HI Offshore Gas Project, which
collectively signal growing confidence in Nigeria as a destination for long-term energy investment.
In collaboration with its JV Parties, the Company is continuing to advance the restart of the Akpo/Egina 2026
drilling campaign following the break in the 2025 program. Work is underway to secure a deepwater rig with
the drilling of the Akpo Far East near -field prospect, the first planned well in the campaign. This will be
followed by the drilling of further infill development wells in the Akpo and Egina fields in late 2026 and into
early 2027. Notably, the pause in the drilling program has created a valuable opportunity for the interpretation
of 4D seismic data focused on the maturation of infill well candidates.
The Akpo Far East prospect presents a strategically-positioned fast-cycle tie-back opportunity that will utilise
the existing Akpo facilities. The prospect lies about 5 km east of the currently producing Akpo field and the
planned drilling approach will assess all prospective resource volumes identified wit hin the prospect. To
support this, efforts are ongoing to complete all the work required to spud the Akpo Far East exploratory well
in 2026.
Work is actively progressing on the remaining subsurface and development opportunities within the PML
2/3/4 license area. Preowei Field subsurface review and development validation activities continued in Q4
2025 with study results expected in H1 2026 to guide the timing and scope of an FID. The planned appraisal
activity by TotalEnergies in the Egina South area in OPL 257, currently expected in 2026, may further de -
risk adjacent resources and, if successful, indicate potential additional value for Meren th rough proximity to
existing infrastructure.
In early 2026, Meren and its JV Parties in PML 2/3 successfully executed an amendment to the gas sales
agreement that includes a revised index for gas pricing, locking in a long-term gas price that is more reflective
of the current LNG economics compared t o 2018 when the contract was initially signed. The amendment
also includes a mechanism for the sellers to recover the historical difference between the interim gas price
adjustment and the new index, starting from 2020 when the previous index ceased to be published. This
historical amount will be recovered through an upward adjustment to the netback pricing that includes the
handling fee for the gas sold, which will improve future gas revenue for the Company.
In Agbami, the FPSO unit life extension studies to ensure long term asset integrity and to enhance operation
performance of the facility , are expected to conclude in 2026. Also , the ongoing 4D seismic interpretation
and rig contracting activities for the Agbami infill drilling program remain on schedule. The Agbami infill drilling
campaign is expected to commence in Q1 2027, following the planned arrival of the rig in Q4 2026 wit h the
Ikija appraisal well being matured to initiate the campaign as the first well.
Namibia Orange Basin Development and Exploration, Blocks 2912 and 2913B
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The Venus Field in Block 2913B remains the most advanced deepwater discovery in the Orange Basin and
is expected to anchor Namibia’s first large -scale offshore oil development. The project is being progressed
by TotalEnergies (Operator, 50.5%) together wit h QatarEnergy (30.0%), NAMCOR (10.0%) and Impact Oil
& Gas (9.5%). Through its shareholding in Impact, Meren holds an effective 3.8 percent indirect interest in
the Venus development. Under Impact’s carried-interest arrangement with TotalEnergies, Meren’s exposure
to all development and exploration costs on Blocks 2912 and 2913B remains fully funded through to first
commercial production, without any financial cap.
The Environmental and Social Impact Assessment (ESIA) for the proposed Venus development has been
completed and published, and the associated Environmental Clearance Certificate (ECC) application has
been submitted to the relevant Namibian authorities. Com pletion of the ESIA represents a key regulatory
milestone, further de -risking the project. FEED work is proceeding on the base -case concept of up to 40
subsea wells tied back to a single FPSO with a nameplate capacity of approximately 160,000 barrels per day
of oil, with reinjection of associated gas offshore. Contractor bids have been received and are within
expectation. The project schedule remains consistent with the current planning framework with FID targeted
for 2026 and first oil in 2030 , subject to the completion of negotiations between the operator and the
government on enhanced fiscal terms for the project, which is expected to be the first producing oil field and
the first deepwater development in Namibia.
The Venus development is regarded by the Namibian government as a strategic national project with the
potential to establish Namibia as a new deepwater oil producer. Appraisal and exploration activities continue
across the broader Orange Basin and addition al prospects are being evaluated using newly acquired 3D
seismic data on Blocks 2912 and 2913B.
Namibia’s oil and gas sector remains active and supportive, with strong investment from international
operators, rollout of a Local Content Policy, and infrastructure upgrades at the Walvis Bay and Lüderitz ports.
Execution and infrastructure challenges, i ncluding marine services capacity, environmental approvals, and
gas monetization, present both risks and opportunities as the country positions itself to attract capital and
expand its deepwater supply chain.
The Venus development presents Meren with a material long -term growth opportunity within a fully carried
structure, offering potential for future cash -flow generation and portfolio optionality with no upfront funding
commitments.
South Africa Orange Basin, Block 3B/4B
On September 16, 2024, the Department of Mineral Resources and Energy for the Republic of South Africa
granted an Environmental Authorization for exploration activities (drilling of up to 5 exploration wells) on the
block. Following that decision, the legislative notification and appeals process in South Africa was suspended
pending a Supreme Court of Appeal judgement in respect of Block 5/6/7. The operator has stated that the
current plan is to drill the first exploration well on Block 3B/4B as soon as the Environmental Authorization is
confirmed and has identified Nayla, a prospect that lies in the northwest of the license area , as the potential
drilling target.
Equatorial Guinea, Blocks EG-18 and EG-31
In late 2025 the Company submitted requests for extensions to the exploration license terms for both blocks.
On December 17, 2025, the Company received notification from the Ministry of Hydrocarbons and Mining
Development in Equatorial Guinea approving extensions of up to two years to the first exploration sub period
on each block.
During the course of 2025, the Company completed a number of data room exercises across the two blocks
and remains actively engaged in advancing potential partnership discussions. Following industry interest
during the data room phase, the Company is now transitioning into the next stage of activity, focused on
advancing discussions with prospective partners. In parallel, the Company continues to coordinate with
government and representatives from GEPetrol to define the forward plan for both blocks.
Should the Company successfully attract a farm -in partner(s) on acceptable terms for these blocks, subject
to customary consents and approvals including governmental and regulatory permissions, the Company
anticipates that newly formed JVs could be positio ned to plan for appraisal and development as well as
exploration drilling in late 2026 or 2027.
While there can be no assurance of securing partners on acceptable terms, the Company remains
encouraged by the level of industry interest and continues to advance partnership discussions with
confidence.
Shareholder Returns
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The Company’s capital allocation framework balances reinvestment in value-accretive organic opportunities
with a commitment to sustainable shareholder returns, while preserving balance sheet strength and financial
flexibility.
Following continued strong operating performance and after consideration of organic investment
requirements and balance sheet resilience, the Company is pleased to announce that its Board has declared
the distribution of the Company’s first quarterly cash dividend in 2026 of approximately $25.1 million or
$0.0371 per share. This dividend will be payable to shareholders of record at the close of business on March
20, 2026.
This dividend qualifies as an ‘eligible dividend’ for Canadian income tax purposes. Dividends for shares
traded on the Toronto Stock Exchange (“TSX”) will be paid in Canadian dollars on April 7, 2026; however, all
US and foreign shareholders will receive USD funds. Dividends for shares traded on Nasdaq Stockholm will
be paid in Swedish Krona in accordance with Euroclear principles at the earliest on April 10, 2026.
To execute the payment of the dividend, a temporary administrative cross border transfer closure will be
applied by Euroclear from March 18, 2026, up to and including March 20, 2026, during which period shares
of the Company cannot be transferred between the TSX and Nasdaq Stockholm.
Payment to shareholders who are not residents of Canada will be net of any Canadian withholding taxes that
may be applicable. For further details, please visit: https://mereninc.com/investor-summary/total-
shareholder-returns/.
The Board views this first quarterly dividend of 2026 to be prudent, having given due consideration to the
Company’s capital allocation options and the Company’s overarching priority of maintaining a robust balance
sheet under a range of market scenarios.
Notwithstanding the foregoing, the decision to declare any dividend or other shareholder distribution and the
amount of future cash dividends declared and paid by Meren or shareholder distributions made by Meren, if
any, will be subject to the discretion of the Board and may vary depending on a variety of factors and
conditions existing from time to time. These may include, without limitation, business performance, operating
environment where Meren’s assets are located, financial condition, growth plans, fl uctuations in commodity
prices, production levels, expected capital expenditure requirements, operating costs, royalties, foreign
exchange rates, interest rates, compliance with any restrictions on the declaration and payment of dividends
contained in any agreements to which Meren or any of its subsidiaries is a party from time to time (including,
without limitation, financing agreements governing the RBL), and the satisfaction of liquidity and solvency
tests imposed by the BC BCA for the declaration and pa yment of dividends. The actual amount, the record
date and the payment date of any dividend are subject to the discretion of the Board. There can be no
assurance that dividends will be paid at the current rate or at any rate in the future.
2026 Management Guidance
The Company’s full-year 2026 production will be generated solely by its deepwater Nigerian assets. The
2026 Management Guidance includes W.I. production guidance range of 23.0 – 28.0 kboepd and entitlement
production range of 28.0 – 33.0 kboepd with approximately 68% expected to be light and medium crude oil
and 32% conventional natural gas on a W.I. basis and 73% and 27% respectively on an entitlement basis .
Meren is expected to sell 8 cargoes of approximately one million barrels each during 2026.
The table below summarizes the Company’s full -year 2026 Management Guidance. These estimates are
based on a 2026 average Brent price of $63.0/bbl.
2026 Guidance 2025 Actuals
WI production (kboepd) i 23.0 – 28.0 30.8
Entitlement production (kboepd) ii 28.0 – 33.0 35.1
EBITDAX ($ million) iii 270.0 – 360.0 440.7
Cash flow from operations ($ million) iii 185.0 – 255.0 261.8
Capital investments ($ million) 100.0 – 140.0 100.2
Notes:
i. Aggregate oil equivalent production data comprised of light and medium crude oil and conventional natural gas
production net to the Company’s W.I. in Agbami, Akpo and Egina fields. These production rates only include sold gas
volumes and not those volumes used for fuel, reinjected or flared.
ii. Entitlement production is calculated using the economic interest methodology and includes cost recovery oil, royalty
oil and profit oil and is different from working interest production that is calculated based on project volumes multiplied
by the Company’s effective working interest in each license.
iii. This table includes non -GAAP measures that do not have a standardized meaning prescribed by IFRS Accounting
Standards and, therefore, may not be comparable with the calculation of similar measures by other companies. The
Company believes that the presentat ion of these non -GAAP figures provides useful information to investors and
shareholders as the measures provide increased transparency. EBITDAX is a non-GAAP measure. This is used as a
performance measure to understand the financial performance from the Co mpany’s business operations without
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including the effects of the capital structure, tax rates, depreciation, depletion, amortization, impairment and exploration
expenses. Cash flow from operations before working capital and interest payments is a non -GAAP measure. This
represents cash generated by removing the impact of working capital movements from cash generated by operating
activities. It is a measure commonly used to better understand cash flow from operations across periods on a consistent
basis, and when viewed in combination with the Company’s results provides a more complete understanding of the
factors and trends affecting the Company’s performance.
Notes
1. Aggregate oil equivalent production data comprised of light and medium crude oil and conventional natural gas
production net to Meren’s W.I. in Agbami, Akpo and Egina fields. These production rates only include sold gas volumes
and not those volumes used for fuel, reinjected or flared.
2. Lifting entitlement production is calculated using the economic interest methodology and includes cost recovery oil, tax
oil, royalty oil and profit oil and is different from working interest production that is calculated based on project volumes
multiplied by Meren’s effective working interest in each license.
3. Includes non-GAAP measures. Definitions and reconciliations to these non -GAAP measures are provided in Fourth
Quarter 2025 MD&A.
4. Cash flow from operations before working capital adjustments and interest payments.
5. Please refer to the oil and gas advisory on page 8 for important information.
6. Based on Brent oil price forecast of ($/bbl): 2026 - $71.0; 2027 - $73.3; 2028 - $74.6; 2029 - $76.1; 2030 – $77.6; 2031
and beyond escalation rate of 2.0%.The valuation include the impact of a lower oil price deck used in this report relative
to the deck used for YE’24, which included a forecast of ($/bbl): 2026 - $76.5; 2027 - $78.0; 2028 – 79.6; 2029 - $81.2;
2030 and beyond escalation rate of 2.0%
7. Net entitlement reserves are calculated using the economic interest methodology and include cost recovery oil, tax oil
and profit oil, but exclude royalty oil, and are different from working interest reserves that are calculated based on
project volumes multiplied by Meren’s effective working interest.
Management Conference Call
Senior management will hold a conference call to discuss the results on Wednesday, February 25 ,
2026, at 09:00 (ET) / 14:00 (GMT) / 15:00 (CET). The conference call may be accessed via webcast.
Participants should use the following link to register for the live webcast:
https://meren-energy-fourth-quarter-results-february-2026.open-exchange.net/registration
1. Click on the link and complete the online registration form.
2. Upon registering you will receive a confirmation email with a sign in link and access code.
About Meren
Meren is a full -cycle Independent upstream oil and gas company with interests offshore Nigeria,
Namibia, South Africa and Equatorial Guinea. Its main assets are producing and development assets
in deepwater Nigeria. The Company holds a leading position in the Orange Basin including its effective
interest in the Venus light oil project, offshore Namibia, and its direct interest in Block 3B/4B, offshore
South Africa.
For further information, please contact:
Shahin Amini
Head of IR and Communications
shahin.amini@mereninc.com
T: +44 (0)20 8017 1511
Burson Buchanan
Financial PR & Communications Advisor
Energy@Buchanan.uk.com
T: +44 (0)20 7466 5000
Visit us at www.mereninc.com.
Additional Information
This information is information that Meren is obliged to make public pursuant to the EU Market Abuse
Regulation and information that Meren is required to make public pursuant to the Swedish Securities
Market Act. The information was submitted for publication, through the agency of the contact persons
set out above, at 5:00 p.m. ET on February 24, 2026.
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Advisory Regarding Oil and Gas Information
The terms boe (barrel of oil equivalent) and MMboe (millions of barrels of oil equivalent) are used
throughout this press release. Such terms may be misleading, particularly if used in isolation. Year-end
2025 reserves estimates are based on a conversion ratio of six thousand cubic feet per barrel of oil
equivalent (6 Mcf: 1 boe), which is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the
value ratio based on the current price of crude oil as compared to natural gas is significantly different
from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an
indication of value.
RISC’s report was prepared using Brent oil price forecast of ($/bbl): 2026 - $71.0; 2027 - $73.3; 2028 -
$74.6; 2029 - $76.1; 2030 – $77.6; 2031 and beyond escalation rate of 2.0%. There is no assurance
that the forecast prices will be attained and variances could be material. The recovery and reserves
estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimat es only
and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas
and natural gas liquids reserves may be greater than or less than the estimates provided herein.
The reserves estimates presented in this press release have been evaluated by RISC in accordance
with NI 51-101 and the COGE Handbook, are effective December 31, 202 5. The reserves presented
herein have been categorized accordance with the reserves and resource definitions as set out in the
COGE Handbook. The estimates of reserves in this press release may not reflect the same confidence
level as estimates of reserves for all properties, due to the effects of aggregation.
Reserves
Reserves are estimated remaining quantities of commercially recoverable oil, natural gas, and related
substances anticipated to be recoverable from known accumulations, as of a given date, based on the
analysis of drilling, geological, geophysical, and eng ineering data, the use of established technology,
and specified economic conditions, which are generally accepted as being reasonable. Reserves are
further categorized according to the level of certainty associated with the estimates and may be sub -
classified based on development and production status.
Proved reserves are those reserves that can be estimated with a high degree of certainty to be
recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved
reserves.
Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than
the sum of the estimated proved plus probable reserves.
Oil and gas reserves and production referred to in this release are for conventional light and medium
gravity oil and conventional natural gas.
Forward-Looking Information
Certain statements and information contained herein constitute "forward-looking information" (within the
meaning of applicable Canadian securities legislation) , including statements related to: the base
dividend distribution; the declaration of the $25 million quarterly dividend; schedules and costs of drilling
activity including those offshore Namibia , Nigeria and South Africa ; the outcome and timing of
exploration, appraisal and development activities including those offshore Namibia and Nigeria ; the
development of the Venus discovery; the ability of Meren to secure farminee partners on acceptable
terms in Equatorial Guinea; the ability of Meren to deliver further growth or increased shareholder
returns including by monetizing its assets; the ability of Meren to grow into a leading independent E&P;
the continuing benefits from funded, high value growth opportunities, including the Venus oil project in
the Orange Basin; expectations regarding free-cash flow; the ability of Meren to influence its JV parties
to sustain and enhance production in Nigeria; and statements regarding access to business
opportunities in Meren’s regions of focus and unlocking new sources of growth capital. Such statements
and information (together, "forward-looking statements") relate to future events or the Company's future
performance, business prospects or opportunities.
===== SIDA 9 =====
- 9 -
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 ar e based on certain assumptions that the
reserves and resources can be economically exploited. Any statements that express or involve
discussions with respect to predictions, expectations, beliefs, plans, projections, objectives,
assumptions or future event s or performance (often, but not always, using words or phrases such as
"seek", "anticipate", "plan", "continue", "estimate", "expect, "may", "will", "project", "predict", "potential",
"targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of
historical fact and may be "forward-looking statements". Forward-looking statements involve known and
unknown risks, ongoing uncertainties and other factors that may cause actual results or events to differ
materially from those anticipated in such forward -looking statements, including statements pertaining
to performance of commodity hedges, uninsured risks , regulatory and fiscal changes, availability of
materials and equipment, unanticipated environmental impacts on operations, duration of the drilling
program, availability of third party service providers and defects in title , the sustainability of Meren
across oil and gas price cycles, the enhanced visibility and certainty over the use of capital, and
statements regar ding capital priorities . Forward-looking statements are based on a number of
assumptions, including but not limited to, the ability of Meren to delivery further growth, the ability to
have a Board comprised at all times of a majority of independent non -executive directors, high value
growth opportunities will continue to be funded, and the ability to access business opportunities in
Meren’s regions of focus. No assurance can be given that these expectations will prove to be correct
and such forward-looking statements should not be unduly relied upon. The Company does not intend,
and does not assume any obligation, to update these forward -looking statements, except as required
by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among
other things, changes in macro -economic conditions and their impact on operations, changes in oil
prices, reservoir and production facility performance, contractual performance, results of exploration
and development activities, cost overruns, uninsured risks, regulatory and fiscal changes including
defects in title, claims and legal proceedings, availability of materials and equipment, availability of
skilled personnel, the need to obtain required approvals from regulatory authorities, timeliness of
government or other regulatory approvals, actual performance of facilities, joint venture partner
underperformance, availability of financing on reasonable terms, hedging, availability of third party
service providers, equipment and processes relative to specifications and expectations and
unanticipated environmental, health and safety impacts on operations , the failure to realize the
anticipated benefits of the amalgamation and the influence of BTG as a significant shareholder on the
actions of the Company . Actual results may differ materially from those expressed or implied by such
forward-looking statements.
===== SIDA 10 =====
For the Year Ended December 31, 2025
Q4
25
Meren Energy Inc. (previously called Africa Oil Corp.)
Report to
Shareholders
===== SIDA 11 =====
Report to Shareholders | December 31, 2025
PAGE 2
A
“Africa Energy” means Africa Energy Corp. an international oil and gas exploration company that holds an effective 4.9%
participating interest in the Exploration Right for Block 11B/12B offshore South Africa.
“Amalgamation”
means the amalgamation transaction 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.
“Applicable law” means all laws and regulations issued by authorities that have appropriate jurisdiction over the Company.
“Azinam” means Azinam Limited, a wholly owned subsidiary of Eco.
B
“Bcf” means billion cubic feet.
“boepd” means barrels of oil equivalent per day.
“BTG Holding” means BTG Pactual Holding S.a.r.l.
“BTG Oil & Gas” means BTG Pactual Oil & Gas S.a.r.l.
C
“CGU”
means Cash Generating Unit. A Cash Generating Unit is defined as assets that are grouped together into
the smallest group of assets that generates cash inflows from continuing use that are largely independent
of the cash inflows of other assets or groups of assets.
“Chevron” means Chevron Corp.
“CIT” means Corporate Income Tax.
“Concessions”
means concessions, PSAs, PSCs and other similar agreements entered into with a host government
providing for petroleum operations in a defined area and the division of petroleum production from the
petroleum operations.
D “DD&A” means Depreciation, Depletion and Amortization.
E
“EBITDAX” means Earnings Before Interest, Taxes, Depreciation & Impairment, Amortization and Exploration
Expenses.
“Eco” means Eco (Atlantic) Oil & Gas Ltd.
“Entitlement
production”
means production that is calculated using the economic interest methodology and includes cost oil, profit
oil, tax oil and royalty oil.
“ESIA” means Environmental and Social Impact Assessment.
F
“FEED” means Front End Engineering and Design.
“FID” means Final Investment Decision.
“FPSO” means Floating Production Storage and Offloading.
G
“GHG” means Greenhouse Gas.
“GTCs” means Gas Turbine Compressors.
I
“IFRS Accounting
Standards”
means International Financial Reporting Standards as issued by the International Accounting Standards
Board.
“Impact”
means Impact Oil and Gas Ltd, a privately owned exploration company with a strategic focus on large
scale, mid to deep water plays of sufficient materiality to be of interest to major companies. Impact has an
asset base across the offshore margins of Southern and West Africa.
J “JV” means Joint Venture.
K “Kenya entities” means Centric Energy Kenya Limited, Africa Oil Kenya B.V Branch and Africa Oil Turkana Limited.
L “LTIP” means Long Term Incentive Plan.
GLOSSARY
===== SIDA 12 =====
Report to Shareholders | December 31, 2025
PAGE 3
M
“Mcf” means million cubic feet.
“Meren”, “MER”, or the
“Company” means Meren Energy Inc.
“Meren Coop” or “Meren
Coöperatief U.A.”
means Meren Coöperatief U.A., previously known as Prime Coöperatief U.A., a company that holds interests
in deepwater Nigeria production and development assets.
“Meren 52” means Meren Nigeria 52 Limited (previously named Prime 127 Nigeria Limited).
“Meren 234” means Meren 234 Nigeria Limited (previously named Prime 130 Nigeria Limited).
“MD&A” means Management’s Discussion and Analysis.
“Mbbl” and “MMbbl” means one thousand and one million barrels, respectively.
“Mboe” and “MMboe” means thousands of barrels of oil equivalent and millions of barrels of oil equivalent, respectively.
N
“NCIB” means Normal Course Issuer Bid.
“NI 51-101” means National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities of the Canadian
Securities Administrators and the companion policies and forms thereto, as amended from time to time.
“NI 52-109” means National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings and
the companion policies and forms thereto, as amended from time to time.
“NUPRC” means Nigerian Upstream Petroleum Regulatory Commission.
P
“PIA” means Petroleum Industry Act.
“PML” means Petroleum Mining Lease.
“PML 2” means the Petroleum Mining Lease containing the Akpo field.
“PML 3” means the Petroleum Mining Lease containing the Egina field.
“PML 4” means the Petroleum Mining Lease containing the Preowei field.
“PML 52” means the Petroleum Mining Lease containing the Agbami field.
“PPL” means Petroleum Prospecting License.
“PPL 2003” means the Petroleum Prospecting License containing the Ikija prospect
“PPL 261” means the Petroleum Prospecting License containing the South Egina prospect.
“PPT” means Profit Petroleum Tax.
“PRMS” means Petroleum Resources Management Reporting System.
“PSA” means Production Sharing Agreement.
“PSC” means Production Sharing Contract.
“PSU” means Performance Share Unit.
R
“RBL” means Reserves Based Lending.
“RSU” means Restricted Share Unit.
S
“SOFR” means Secured Overnight Financing Rate.
“spud” or “spudded” means the initial drilling for an oil well.
T
“TAM” means planned turnaround maintenance.
“TotalEnergies” means TotalEnergies SE and subsidiaries.
“TSX” means Toronto Stock Exchange.
U “US” means United States.
W
“WI” means working interest.
“WI production” means production based on the percentage of working interest owned.
===== SIDA 13 =====
Report to Shareholders | December 31, 2025
PAGE 4
MANAGEMENT’S DISCUSSION AND ANALYSIS
The Management’s Discussion and Analysis (“MD&A”) focuses on significant factors that have affected the Company during the year ended
December 31, 2025, and such factors that may affect its future performance. To better understand the MD&A, it should be read in conjunction
with the Company’s audited consolidated financial statements for the years ended December 31, 2025, and 2024, and related notes thereto.
The financial information in this MD&A is derived from the Company’s audited consolidated financial statements which have been prepared in
US dollars, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS
Accounting Standards”).
This MD&A was reviewed and approved by the Board of Directors. The effective date of this MD&A is February 24, 2026.
Additional information about the Company and its business activities is available on the Company’s website at www.mereninc.com and on
SEDAR+ at www.sedarplus.com.
The Company changed its name to Meren Energy Inc. on May 14, 2025, and was previously called Africa Oil Corp.
PROFILE AND STRATEGY
Meren is a Canadian oil and gas company with producing and development assets in deep-water offshore Nigeria. The Company also has a
portfolio of development and exploration assets in West and South of Africa.
The Company’s Common Shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in Sweden, under
the symbol ‘MER’.
The Company’s common shares also trade on the OTCQX Best Market (“OTCQX”) in the U.S. under the ticker ‘MRNFF’.
Meren’s strategy is anchored in maintaining a resilient balance sheet through the cycle, prioritizing high-return organic investment in its core
assets, and delivering sustainable shareholder returns from surplus free cash flow. This plan is supported by the Company’s high netback
production assets in Nigeria that are included in its interests in Petroleum Mining Leases (“PMLs”) 2, 3, 4 and 52. These PMLs provide the Company
with a long-life cash flowing asset base, to support its business objectives over the long term, and also present development opportunities for
supporting future production together with the Company’s interests in Petroleum Prospecting Licenses (“PPLs”) 261 and 2003.
The Company’s other core assets are comprised of its Orange Basin opportunity set including Blocks 2912 and 2913B offshore Namibia and
Block 3B/4B, offshore South Africa, as well as Equatorial Guinean exploration and appraisal blocks (EG-18 and EG-31).
The Company is a unique investment opportunity, amongst its publicly-listed independent E&P peer group, for its Orange Basin opportunity set
that includes an effective interest in the Venus light oil and associated gas discovery offshore Namibia. The Venus discovery, understood to
be the largest oil discovery globally in 2022, has partially de-risked a new petroleum province in the Orange Basin that has significant further
prospectivity.
HIGHLIGHTS AND OUTLOOK
Full-Year 2025, Q4 2025 AND POST PERIOD HIGHLIGHTS
● During 2025, closed the transformative Prime amalgamation to take full control of Prime’s assets, doubling Meren’s reserves and production;
● Distributed approximately $100 million to the Company’s shareholders under the base dividend policy and repurchased 5.9 million shares at
a cost of approximately $8 million;
● Achieved average daily W.I and entitlement production of 30,800 boepd and 35,100 boepd, respectively, for 2025, in line with the revised
full-year management guidance;
● Sold three cargos in Q4 2025 at an average sales price of $64.4/bbl and twelve cargos in 2025 at an average sales price of $72.2/bbl, both
of which were higher than average Dated Brent for the same periods;
● In 2025 reduced the RBL by $420.0 million, reducing interest expenses and ending 2025 with a debt balance of $330.0 million.
● End of 2025 cash balance of $174.7 million resulting in a net debt position of $155.3 million with a Net Debt/ EBITDAX of 0.4x as at
December 31, 2025, with a RBL facility headroom of $138.4 million.
» EBITDAX of $440.7 million;
» Cashflow from operations before working capital adjustment of $261.8 million; and
» Cash capital investments of $100.2 million.
● Reported net loss of $31.6 million ($0.05/share) for full-year 2025, primarily from to a non-cash impairment of $105.3 million for the
Agbami cash generating unit (“CGU”) reflecting a more conservative oil price and cost outlook compared to prior assumptions.
● Following continued strong operating performance and after consideration of organic investment requirements and balance sheet resilience,
the Board has declared the first quarterly dividend in 2026 of approximately $25.1 million;
● On February 2, 2026, the Company announced that Roger Tucker had stepped down from the role of President and CEO and as a director
of Meren, and that Oliver Quinn had been appointed as his successor and joined the Board as a director.
===== SIDA 14 =====
Report to Shareholders | December 31, 2025
PAGE 5
● Meren’s year-end 2025 reserves:
» YE’25 reserves determination has delivered after-tax 1P NPV(10) and 2P NPV(10) valuations of $588 million (YE’24: $1,248 million) and
$1,499 million (YE’24: $2,128 million) respectively.
» YE’25 W.I. and net entitlement7 1P reserves of 48.8 MMboe (YE’24: 59.8 MMboe) and 62.5 MMboe (YE’24: 70.8 MMboe), respectively.
» YE’25 W.I. and net entitlement 2P reserves of 87.7 MMboe (YE’24: 101.6 MMboe) and 107.4 MMboe (YE’24: 116.4 MMboe), respectively.
» YE’25 aggregate W.I. 2P reserves and 2C contingent resources of 140.2 MMboe (YE’24: 129.6 MMboe).
FINANCIAL SUMMARY (1)
Three months ended Years ended
Meren highlights Unit
December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
Net (loss)/ income $’m (90.8) 6.2 (31.6) (279.1)
Net (loss)/ income per share – basic (2) $/ share (0.13) 0.02 (0.05) (0.62)
Net debt position (3) $’m 155.3 289.1 155.3 289.1
WI production (3) boepd 28,100 34,400 30,800 34,000
Entitlement production (3) boepd 31,500 39,000 35,100 38,800
Cash flow from operations (4, 5) $’m 18.7 n/a 261.8 n/a
EBITDAX (4) $’m 72.7 n/a 440.7 n/a
Capital investments (4) $’m 19.8 n/a 100.2 n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on pages 14 - 17.
(2) Based on the weighted average number of shares outstanding for the three months and year ended December 31, 2025, of 675,685,556 and
624,464,015 respectively, which accounts for the newly issued shares to BTG Oil & Gas on March 19, 2025.
(3) Net debt position and production numbers as presented for the comparative periods includes 100 percent of Meren Coop to be comparable with net
debt position and production numbers for the three months and year ended December 31, 2025.
(4) Highlights are reported for the year 2025 only, on a constructed financial information basis, see pages 10 - 12 for further information.
(5) Cash flow from operations before working capital and interest payments.
OUTLOOK
Nigeria
Nigeria’s macroeconomic and sector-specific reforms are beginning to show tangible results, with improved fiscal clarity, stronger government
engagement, and targeted incentives aimed at sustaining investment in the oil and gas sector. The Federal Government has reaffirmed its
support for upstream development through regulatory stability and commercial incentives, contributing to renewed capital commitment across
offshore oil and gas projects. This improved investment climate is evidenced by recent final investment decisions on major developments such
as Bonga North, Ubeta Gas Project, and HI Offshore Gas Project, which collectively signal growing confidence in Nigeria as a destination for
long-term energy investment.
In collaboration with its JV Parties, the Company is continuing to advance the restart of the Akpo/Egina 2026 drilling campaign following the
break in the 2025 program. Work is underway to secure a deepwater rig with the drilling of the Akpo Far East near-field prospect, the first
planned well in the campaign. This will be followed by the drilling of further infill development wells in the Akpo and Egina fields in late 2026
and into early 2027. Notably, the pause in the drilling program has created a valuable opportunity for the interpretation of 4D seismic data
focused on the maturation of infill well candidates.
The Akpo Far East prospect presents a strategically positioned fast-cycle tie-back opportunity that will utilise the existing Akpo facilities. The
prospect lies about 5 km east of the currently producing Akpo field and the planned drilling approach will assess all prospective resource
volumes identified within the prospect. To support this, efforts are ongoing to complete all the work required to spud the Akpo Far East
exploratory well in 2026.
===== SIDA 15 =====
Report to Shareholders | December 31, 2025
PAGE 6
HIGHLIGHTS AND OUTLOOK - CONTINUED
Work is actively progressing on the remaining subsurface and development opportunities within the PML 2/3/4 license area. Preowei Field
subsurface review and development validation activities continued in Q4 2025 with study results expected in H1 2026 to guide the timing and
scope of an FID. The planned appraisal activity by TotalEnergies in the Egina South area in OPL 257, currently expected in 2026, may further
de-risk adjacent resources and, if successful, indicate potential additional value for Meren through proximity to existing infrastructure.
In early 2026, Meren and its JV Parties in PML 2/3 successfully executed an amendment to the gas sales agreement that includes a revised
index for gas pricing, locking in a long-term gas price that is more reflective of the current LNG economics compared to 2018 when the contract
was initially signed. The amendment also includes a mechanism for the sellers to recover the historical difference between the interim gas price
adjustment and the new index, starting from 2020 when the previous index ceased to be published. This historical amount will be recovered
through an upward adjustment to the netback pricing that includes the handling fee for the gas sold.
In Agbami the FPSO unit life extension studies, to ensure long term asset integrity and to enhance operation performance of the facility are
expected to conclude in 2026. Also, the ongoing 4D seismic interpretation and rig contracting activities for the Agbami infill drilling program
remain on schedule. The Agbami infill drilling campaign is expected to commence in Q1 2027, following the planned arrival of the rig in Q4 2026
with the Ikija appraisal well being matured to initiate the campaign as the first well.
Namibia Orange Basin Development and Exploration, Blocks 2912 and 2913B
The Venus Field in Block 2913B remains the most advanced deepwater discovery in the Orange Basin and is expected to anchor Namibia’s first
large-scale offshore oil development. The project is being progressed by TotalEnergies (Operator, 50.5%) together with QatarEnergy (30.0%),
NAMCOR (10.0%) and Impact Oil & Gas (9.5%). Through its shareholding in Impact, Meren holds an effective 3.8 percent indirect interest in
the Venus development. Under Impact’s carried-interest arrangement with TotalEnergies, Meren’s exposure to all development and exploration
costs on Blocks 2912 and 2913B remains fully funded through to first commercial production, without any financial cap.
The Environmental and Social Impact Assessment (ESIA) for the proposed Venus development has been completed and published, and the
associated Environmental Clearance Certificate (ECC) application has been submitted to the relevant Namibian authorities. Completion of the
ESIA represents a key regulatory milestone, further de-risking the project. FEED work is proceeding on the base-case concept of up to 40 subsea
wells tied back to a single FPSO with a nameplate capacity of approximately 160,000 barrels per day of oil, with reinjection of associated gas
offshore. Contractor bids have been received and are within expectation. The project schedule remains consistent with the current planning
framework with FID targeted for 2026 and first oil in 2030, subject to the completion of negotiations between the operator and the government
on enhanced fiscal terms for the project, which is expected to be the first producing oil field and the first deepwater development in Namibia.
The Venus development is regarded by the Namibian government as a strategic national project with the potential to establish Namibia as a
new deepwater oil producer. Appraisal and exploration activities continue across the broader Orange Basin and additional prospects are being
evaluated using newly acquired 3D seismic data on Blocks 2912 and 2913B.
Namibia’s oil and gas sector remains active and supportive, with strong investment from international operators, rollout of a Local Content
Policy, and infrastructure upgrades at the Walvis Bay and Lüderitz ports. Execution and infrastructure challenges, including marine services
capacity, environmental approvals, and gas monetization, present both risks and opportunities as the country positions itself to attract capital
and expand its deepwater supply chain.
The Venus development presents Meren with a material long-term growth opportunity within a fully carried structure, offering potential for
future cash-flow generation and portfolio optionality with no upfront funding commitments.
South Africa Orange Basin, Block 3B/4B
On September 16, 2024, the Department of Mineral Resources and Energy for the Republic of South Africa granted an Environmental
Authorization for exploration activities (drilling of up to 5 exploration wells) on the block. Following that decision, the legislative notification
and appeals process in South Africa was suspended pending a Supreme Court of Appeal judgement in respect of Block 5/6/7. The operator has
stated that the current plan is to drill the first exploration well on Block 3B/4B as soon as the Environmental Authorization is confirmed and
has identified Nayla, a prospect that lies in the northwest of the license area, as the potential drilling target.
Equatorial Guinea, Blocks EG-18 and EG-31
In late 2025 the Company submitted requests for extensions to the exploration license terms for both blocks. On December 17, 2025, the
Company received notification from the Ministry of Hydrocarbons and Mining Development in Equatorial Guinea approving extensions of up to
two years to the first exploration sub period on each block.
During the course of 2025, the company completed a number of data room exercises across the two blocks and remains actively engaged
in advancing potential partnership discussions. Following industry interest during the data room phase, the Company is now transitioning into
the next stage of activity, focused on advancing discussions with prospective partners. In parallel, the Company continues to coordinate with
government and representatives from GEPetrol to define the forward plan for both blocks.
Should the Company successfully attract a farm-in partner(s) on acceptable terms for these blocks, subject to customary consents and
approvals including governmental and regulatory permissions, the Company anticipates that newly formed JVs could be positioned to plan for
appraisal and development as well as exploration drilling in late 2026 or 2027.
While there can be no assurance of securing partners on acceptable terms, the Company remains encouraged by the level of industry interest
and continues to advance partnership discussions with confidence.
===== SIDA 16 =====
Report to Shareholders | December 31, 2025
PAGE 7
HIGHLIGHTS AND OUTLOOK - CONTINUED
Shareholder Returns
The Company’s capital allocation framework balances reinvestment in value-accretive organic opportunities with a commitment to sustainable
shareholder returns, while preserving balance sheet strength and financial flexibility.
Following continued strong operating performance and after consideration of organic investment requirements and balance sheet resilience,
the Company is pleased to announce that its Board has declared the distribution of the Company’s first quarterly cash dividend in 2026 of
approximately $25.1 million or $0.0371 per share. This dividend will be payable to shareholders of record at the close of business on March
20, 2026.
This dividend qualifies as an ‘eligible dividend’ for Canadian income tax purposes. Dividends for shares traded on the Toronto Stock Exchange
(“TSX”) will be paid in Canadian dollars on April 7, 2026; however, all US and foreign shareholders will receive USD funds. Dividends for shares
traded on Nasdaq Stockholm will be paid in Swedish Krona in accordance with Euroclear principles at the earliest on April 10, 2026.
To execute the payment of the dividend, a temporary administrative cross border transfer closure will be applied by Euroclear from March 18,
2026, up to and including March 20, 2026, during which period shares of the Company cannot be transferred between the TSX and Nasdaq
Stockholm.
Payment to shareholders who are not residents of Canada will be net of any Canadian withholding taxes that may be applicable. For further
details, please visit: https://mereninc.com/investor-summary/total-shareholder-returns/.
The Board views this first quarterly dividend of 2026 to be prudent, having given due consideration to the Company’s capital allocation options
and the Company’s overarching priority of maintaining a robust balance sheet under a range of market scenarios. Future dividend declarations
will be subject to customary Board approval and consents.
2026 MANAGEMENT GUIDANCE
The Company’s full-year 2026 production will be generated solely by its deepwater Nigerian assets. The 2026 Management Guidance includes
W.I. production guidance range of 23.0 – 28.0 kboepd and entitlement production range of 28.0 – 33.0 kboepd with approximately 68%
expected to be light and medium crude oil and 32% conventional natural gas on a W.I. basis and 73% and 27% respectively on an entitlement
basis. Meren is expected to sell 8 cargoes of approximately one million barrels each during 2026.
The table below summarizes the Company’s full-year 2026 Management Guidance. These estimates are based on a 2026 average Brent price
of $63.0/bbl.
2026 Guidance 2025 Actuals
WI production (kboepd) (1) 23.0 – 28.0 30.8
Entitlement production (kboepd) (2) 28.0 – 33.0 35.1
EBITDAX ($ million) (3) 270.0 – 360.0 440.7
Cash flow from operations ($ million) (3) 185.0 – 255.0 261.8
Capital investments ($ million) 100.0 – 140.0 100.2
(1) Aggregate oil equivalent production data comprised of light and medium crude oil and conventional natural gas production net to the Company’s
W.I. in Agbami, Akpo and Egina fields. These production rates only include sold gas volumes and not those volumes used for fuel, reinjected or flared.
(2) Entitlement production is calculated using the economic interest methodology and includes cost recovery oil, royalty oil and profit oil and is different
from working interest production that is calculated based on project volumes multiplied by the Company’s effective working interest in each license.
(3) This table includes non-GAAP measures that do not have a standardized meaning prescribed by IFRS Accounting Standards and, therefore, may not
be comparable with the calculation of similar measures by other companies. The Company believes that the presentation of these non-GAAP figures
provides useful information to investors and shareholders as the measures provide increased transparency. EBITDAX is a non-GAAP measure. This
is used as a performance measure to understand the financial performance from the Company’s business operations without including the effects
of the capital structure, tax rates, depreciation, depletion, amortization, impairment and exploration expenses. Cash flow from operations before
working capital and interest payments is a non-GAAP measure. This represents cash generated by removing the impact of working capital movements
from cash generated by operating activities. It is a measure commonly used to better understand cash flow from operations across periods on a
consistent basis, and when viewed in combination with the Company’s results provides a more complete understanding of the factors and trends
affecting the Company’s performance.
===== SIDA 17 =====
Report to Shareholders | December 31, 2025
PAGE 8
THE COMPANY’S SHAREHOLDING AND
WORKING INTERESTS
The Company’s material interests and material exploration partnership interests as at December 31, 2025, are summarized in the following
table:
Meren’s Direct Working Interests (1)
Country Concession License renewal Working Interests
Nigeria
PML 52 and PPL 2003 (2) November 24, 2044
Meren
Chevron (Operator)
Famfa Oil
8%
32%
60% (carried)
PML 2, 3, 4 and PPL 261 –
PSA (3) May 24, 2043
Meren
TotalEnergies (Operator)
SAPETRO
32%
48%
20% (carried)
South Africa Block 3B/4B October 26, 2024 (4)
Meren
TotalEnergies (Operator)
QatarEnergy
Azinam
Ricocure (Pty) Ltd
18%
33%
24%
5.25%
19.75%
Equatorial Guinea
EG-18 March 1, 2027(5)
Meren (Operator)
GEPetrol
80%
20%
EG-31 February 29, 2028
Meren (Operator)
GEPetrol
80%
20%
Meren’s Shareholding in Impact (39.5%)
Country Concession License renewal Working Interests
Namibia
PEL 56 (Block 2913B) March 31, 2026
Impact
TotalEnergies
QatarEnergy
NAMCOR
9.5%
50.5%
30%
10% (carried)
PEL 91 (Block 2912) October 1, 2027
Impact
TotalEnergies
QatarEnergy
NAMCOR
9.5%
47.2%
28.3%
15% (carried)
(1) Net WI are subject to back-in rights or carried WI, if any, of the respective governments or national oil companies of the host governments.
(2) Production currently from PML 52 and potential future production from PPL 2003 is covered by a PSA framework, in which Meren owns an 8% WI.
(3) 50% of the production (currently from PMLs 2 and 3, future production from PML 4 and potential future production from PPL 261) is covered by a
PSA framework, in which Meren owns a 32% WI. Meren’s net WI in these assets is therefore 16%.
(4) The operator has submitted an application for license renewal. This is currently awaiting Government approval.
(5) The Company has the option to extend the term of the first exploration sub-period of Block EG-18 by a further twelve months from March 1, 2027,
to February 28, 2028 (inclusive), at its sole discretion.
Information on the Company’s equity interests in Africa Energy and Impact is included in “Equity Investments in Associates” on page 19.
===== SIDA 18 =====
Report to Shareholders | December 31, 2025
PAGE 9
BUSINESS UPDATE
SHAREHOLDER RETURNS
During 2025, the Company distributed approximately $100.2 million and repurchased a total of 5,905,853 at an approximate cost of $8.3
million for an aggregate return of $108.5 million for the year.
The Company’s shareholder returns policy consists of an annual base dividend of $100.0 million, supplemented by additional distributions, either
through dividends or share buybacks, equivalent to up to 50% of free cash flow generated after payment of the base dividend, each of which
remains subject to determination by the Board in its discretion and to a variety of factors and conditions existing from time to time.
On this basis, and after payment of the $100 million base dividend, the Company did not generate additional free cash flow in 2025 available
for further distributions and accordingly the aggregate return of $108.5 million represents the full extent of shareholder distributions for 2025.
As detailed in the Highlights and Outlook section, the Company has declared the distribution of the Company’s first quarterly cash dividend in
2026 of approximately $25.1 million or $0.0371 per share.
Notwithstanding the foregoing, the decision to declare any dividend or other shareholder distribution and the amount of future cash dividends
declared and paid by Meren or shareholder distributions made by Meren, if any, will be subject to the discretion of the Board and may vary
depending on a variety of factors and conditions existing from time to time. These may include, without limitation, business performance,
operating environment where Meren’s assets are located, financial condition, growth plans, fluctuations in commodity prices, production levels,
expected capital expenditure requirements, operating costs, royalties, foreign exchange rates, interest rates, compliance with any restrictions
on the declaration and payment of dividends contained in any agreements to which Meren or any of its subsidiaries is a party from time to time
(including, without limitation, financing agreements governing the RBL), and the satisfaction of liquidity and solvency tests imposed by the BC
BCA for the declaration and payment of dividends. The actual amount, the record date and the payment date of any dividend are subject to the
discretion of the Board. There can be no assurance that dividends will be paid at the current rate or at any rate in the future.
Pursuant to the Company’s current Normal Course Issuer Bid (“NCIB”) share repurchase program that was launched on December 8, 2025,
Meren is authorized to repurchase through the facilities of the TSX, Nasdaq Stockholm and/or alternative Canadian trading systems, as and
when considered advisable by Meren, up to 21,636,913 Common Shares of the Company for a total maximum amount of $35.0 million, which
represented 5% of its “public float” of 432,738,277 Common Shares as at November 24, 2025. As of the same date, Meren had 675,725,593
Common Shares issued and outstanding.
Purchases of Common Shares may occur over a period of up to twelve months commencing December 8, 2025, and ending on the earlier of
December 7, 2026, the date on which the Company has purchased the maximum number of Common Shares permitted under the NCIB, and
the date on which the NCIB is terminated by Meren. There cannot be any assurances as to the number of Common Shares that will ultimately
be acquired by the Company. Any Common Shares purchased by Meren under the NCIB will be cancelled.
GROUP OPERATIONS
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 & Gas Coöperatief U.A) (“Meren Coop”). The transaction 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 “amalgamation”).
The production numbers included in the narrative discussion below include 100 percent of Meren Coop production numbers for all periods to
have comparable production numbers for the purpose of this MD&A.
PRODUCTION AND OPERATIONS
Production Metrics – rounded
Three months ended Years ended
Unit
December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
Total gross field production boepd 207,400 270,300 241,900 273,600
Average daily WI production (1) boepd 28,100 34,400 30,800 34,000
Average daily entitlement production boepd 31,500 39,000 35,100 38,800
Oil volumes sold MMbbl 3.0 - 12.0 9.0
Gas volumes sold bcf 5.1 5.0 19.7 17.4
Oil/gas percentage split (2) % 67%/33% 74%/26% 71%/29% 77%/23%
(1) Production allocation occurs periodically and can result in a change in production numbers previously reported.
(2) Calculated on a working interest basis.
===== SIDA 19 =====
Report to Shareholders | December 31, 2025
PAGE 10
BUSINESS UPDATE - CONTINUED
The total gross field production in Q4 2025 decreased compared to Q4 2024, primarily due to the planned turnaround maintenance (“TAM”)
on the Agbami FPSO and, to a lesser extent, the expected natural reservoir decline across the portfolio together with the operational events
described below. Throughout the quarter, production was actively managed in response to these challenges.
At Akpo and Egina, Q4 production was impacted by plant and compressor trips, including temporary shutdowns related to power supply
issues, particularly during the second half of the quarter. These issues were actively managed through targeted operational interventions and
maintenance activities, enabling operations and the fields to continue performing in line with expectations following resolution.
In addition to the planned extensive turnaround maintenance on the Agbami FPSO, production was impacted by additional work on the Gas
Turbine Compressors (“GTCs”) prior to and during the TAM exercise. The ramp-up following the full-field shutdown was further impacted by GTC
start-up sequencing issues as well as planned work on the seawater injection system. The issues were addressed through focused repair and
optimization efforts resulting in the gas compressors and the seawater injection pumps progressively brought back online by mid-January, two
GTCs and one seawater injection pump were operational, with all GTCs fully online by mid-February. The maintenance and remediation work
completed during the quarter is expected to support improved operational reliability and uptime going forward.
In Q4 2025, three oil liftings were allocated with a total sales volume of approximately 3.0 million barrels of oil at an average realized oil price
of $64.4/bbl, compared to Dated Brent average of $63.7/bbl. In Q4 2024, no oil liftings were allocated.
In 2025, a total of 12 oil liftings were allocated with a total sales volume of approximately 12.0 million barrels of oil at an average realized
oil price of $72.2/bbl, compared to Dated Brent average of $69.1/bbl. In 2024, 9 oil liftings were allocated with a total sales volume of
approximately 9.0 million barrels at an average realized oil price of $84.6/bbl.
FINANCIAL
Total net revenues, cost of sales, gross profit, opex/boe, tax and net debt numbers included in the narrative discussion below, on a constructed
financial information basis, include 100 percent of Meren Coop numbers for all periods to have comparable numbers for the purpose of
this MD&A and includes certain adjustments and reclassifications in the comparative periods to conform with Meren accounting policies and
presentation in the Company’s Consolidated Statement of Net Income or Loss and Other Comprehensive Income or Loss following completion
of the amalgamation.
Cash flow from operations, free cash flow, capex and EBITDAX numbers included in the narrative discussion below have been reported for the
year 2025 only on a constructed financial information basis.
Constructed financial information (non-GAAP measure) to explain performance is included in the following tables to present on a consolidated
basis, net income for 2025 and the cash flow statement for 2025, whereby the Meren Consolidated Statement of Net Income or Loss and Other
Comprehensive Income or Loss and the Meren Consolidated Statement of Cash Flows for 2025 are combined with the Meren Coop Statement
of Net Income and Comprehensive Income and the Meren Coop Statement of Cash Flows for the period until March 19, 2025. Adjustments
included in the constructed financial information are to conform Meren Coop financial information with Meren accounting policies and for any
transactions between Meren and Meren Coop prior to amalgamation for the purpose of presenting constructed financial information to explain
performance.
The constructed financial information does not necessarily reflect what the combined company’s financial condition and results of operations
would have been had the amalgamation occurred on January 1, 2025. Adjustments have been made to prepare the constructed financial
information, which are based on certain assumptions. Both the adjustments and the assumptions made are described in the footnotes to the
constructed financial information. The constructed financial information is presented for illustrative purposes only and are not necessarily
indicative of: (i) the operating or financial results that would have occurred had the amalgamation actually occurred at the times contemplated
by the constructed financial information; or (ii) the results expected in future periods. The constructed financial information are non-GAAP
measures. Refer to more information on the non-GAAP measures provided on pages 11 - 17.
===== SIDA 20 =====
Report to Shareholders | December 31, 2025
PAGE 11
Constructed financial information for purposes of explaining performance
Condensed Consolidated Statement of Net Income/ (Loss)
(Expressed in millions of United States Dollars)
Year ended
Meren 2025
per Financial
Statements
Meren Coop
for period from
January 1, 2025, to
March 19, 2025 Adjustments (1)
December 31,
2025
Oil and gas sales 559.9 323.5 - 883.4
Net Revenue 559.9 323.5 - 883.4
Commodity risk management contracts 2.2 - - 2.2
Revenue 562.1 323.5 - 885.6
Cost of Sales
Movements on overlift/underlift balances (46.3) (133.1) - (179.4)
Production costs (166.6) (54.3) 2.0 (218.9)
Depletion costs (207.9) (71.3) - (279.2)
Impairment charges (105.3) - - (105.3)
(526.1) (258.7) 2.0 (782.8)
Gross profit 36.0 64.8 2.0 102.8
General and administrative expenses (36.4) (6.2) - (42.6)
Operating (loss)/ profit (0.4) 58.6 2.0 60.2
Finance income 4.1 2.4 - 6.5
Finance expense (47.8) (21.3) - (69.1)
Net financial items (43.7) (18.9) - (62.6)
Share of profit from investment in joint venture 2.9 - (2.9) -
Share of loss from investments in associates (2.9) - - (2.9)
Reversal of impairment of investment in joint venture 55.9 - (55.9) -
Profit before tax 11.8 39.7 (56.8) (5.3)
Income tax (43.4) (34.0) - (77.4)
Net income/ (loss) attributable to common shareholders (31.6) 5.7 (56.8) (82.7)
(1) Adjustments to remove items related to Meren Coop as fully consolidated above.
===== SIDA 21 =====
Report to Shareholders | December 31, 2025
PAGE 12
BUSINESS UPDATE - CONTINUED
Condensed Consolidated Statement of Cash Flows
(Expressed in millions of United States Dollars)
Year ended
Meren 2025
per Financial
Statements
Meren Coop
for period from
January 1, 2025, to
March 19, 2025 Adjustments (1)
December 31,
2025
Cash flows generated by/ (used in):
Operations
Profit before tax 11.8 39.7 (56.8) (5.3)
Adjustments as per financial statements 166.8 41.5 58.8 267.1
Net cash generated in operating activities before working
capital 178.6 81.2 2.0 261.8
Changes in working capital 94.0 (8.2) - 85.8
Net cash generated in operating activities 272.6 73.0 2.0 347.6
Investing
Investments in oil and gas properties and intangible
exploration assets (75.6) (22.6) (2.0) (100.2)
Investments in other fixed assets (0.4) - - (0.4)
Distribution received from joint venture 60.0 - (60.0) -
Distribution received from associates 31.6 - - 31.6
Loan repaid by associated company 4.5 - - 4.5
Interest income received 4.2 2.2 - 6.4
Cash acquired from Meren Coop consolidation (2) 380.4 - (381.3) (0.9)
Net cash generated/ (used) in investing activities 404.7 (20.4) (443.3) (59.0)
Financing
Repayment RBL Facility (420.0) - - (420.0)
Repayment of principal portion of lease commitments (0.7) - - (0.7)
Dividends paid to shareholders (100.2) (120.0) 120.0 (100.2)
Repurchase of share capital (8.3) - - (8.3)
Interest expense paid (34.8) (10.8) - (45.6)
Net cash (used)/ generated in financing activities (564.0) (130.8) 120.0 (574.8)
Foreign exchange variation on cash and cash equivalents - - - -
Total cash flow 113.3 (78.2) (321.3) (286.2)
Cash and cash equivalents, beginning of the period 61.4 399.5 - 460.9
Cash and cash equivalents, end of the period 174.7 321.3 (321.3) 174.7
(1) Adjustments to remove items related to Meren Coop as Meren Coop fully consolidated above
(2) Reflects impact of net cash movement on the level of BTG Pactual Holding S.à.r.l.
===== SIDA 22 =====
Report to Shareholders | December 31, 2025
PAGE 13
BUSINESS UPDATE - CONTINUED
Financial Metrics (1,2)
Three months ended Years ended
Unit
December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
Total net revenues $’m 197.5 4.4 883.4 782.7
Cost of Sales (3) $’m 277.9 (67.4) 782.8 428.2
Gross profit $’m (78.2) 71.8 102.8 354.5
Opex/boe (4,5) $/boe 12.0 9.9 11.9 10.3
Cash flow from operations before working
capital $’m 18.7 n/a 261.8 n/a
Cash flow from operations $’m 79.1 n/a 347.6 n/a
Free cash flow $’m 59.9 n/a 288.6 n/a
Free cash flow/boe (5) $/boe 20.7 n/a 22.5 n/a
Tax $’m (4.9) 44.2 77.4 120.5
Capex $’m 19.8 n/a 100.2 n/a
Net Debt $’m 155.3 289.1 155.3 289.1
EBITDAX $’m 72.7 n/a 440.7 n/a
Net Debt/EBITDAX ratio 0.4 n/a 0.4 n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on pages 14 - 17.
(2) Some of the figures presented in the table have been reported on a constructed basis.
(3) Given the nature of the Company’s operations in terms of oil cargo liftings and the variability in their frequency from one quarter to next, the non-
cash accounting treatment of underlift/overlift and the timing between recording revenues and receipts of sales cash, leads to high variability in
quarterly financial metrics. Please refer to the commentary in the rest of this section for the specific details of this period’s changes relative to the
corresponding historical period.
(4) Opex represents direct production costs.
(5) Boe is calculated on an entitlement basis.
Total Net Revenues (1)
Three months ended Years ended
Unit
December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
Oil revenue $’m 193.2 - 864.3 762.2
Gas revenue $’m 4.3 4.4 19.1 20.5
Total net revenue $’m 197.5 4.4 883.4 782.7
Realized oil prices (2) $/bbl 64.4 - 72.2 84.6
Oil volumes sold MMbbl 3.0 - 12.0 9.0
Realized gas prices $’m/bcf 0.8 1.0 1.0 1.2
Gas volumes sold Bcf 5.1 5.0 19.7 17.4
(1) Net revenues have been reported for the year 2025 and 2024 on a constructed financial information basis.
(2) Realized oil prices might be different to values calculated from the table above due to rounding.
===== SIDA 23 =====
Report to Shareholders | December 31, 2025
PAGE 14
BUSINESS UPDATE - CONTINUED
The increase in oil revenue in Q4 2025 was driven by 3 liftings in Q4 2025 compared to none in Q4 2024 as cargos that were initially scheduled
for Q4 2024 were pushed into Q1 2025.
The increase in oil revenue in 2025 was mainly driven by higher liftings in 2025 despite a lower realized oil price of $72.2/bbl in 2025 compared
to $84.6/bbl in 2024.
Cost of sales (1)
Three months ended Years ended
$’m
December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
Depletion costs 52.9 87.0 279.2 372.0
Cost of operations 34.7 35.7 151.7 146.1
Movements on overlift/ underlift balances 63.4 (204.8) 179.4 (171.2)
Royalties – oil and gas 7.3 14.0 41.1 70.2
Others 14.3 0.7 26.1 11.1
Impairment charges 105.3 - 105.3 -
Total cost of sales 277.9 (67.4) 782.8 428.2
(1) Cost of sales has been reported for the year 2025 and 2024 on a constructed financial information basis.
Cost of sales increased in Q4 2025 and 2025 compared to Q4 2024 and 2024 primarily due to anon-cash impairment recognized in relation
to its oil and gas properties in the Agbami field CGU as a result of a combination of increased costs and lower oil prices, and cargos initially
scheduled for Q4 2024 that were pushed into Q1 2025 resulting in a large overlift position in 2025 and a large underlift position in 2024 which
is a credit to cost of sales. This increase in costs of sales was partly offset by lower depletion costs and lower royalties as a result of lower
production volumes and lower oil prices.
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.
These activities are also expected to enhance the flexibility of the Agbami FPSO to support future infill drilling and potential nearby tie-in
opportunities, consistent with the Company’s long-term organic growth strategy. Such potential upside relates to contingent resources which
are not included in the recoverable amount of the CGU for impairment testing purposes. The non-cash impairment does not reflect any adverse
change in reservoir performance, reserves classification or the operational integrity of the Agbami field. The impairment resulted in a reduction
in the deferred tax liability associated with oil and gas properties which has partially offset the impairment charge.
Other costs of sales mainly relate to the NDDC Levy, which concerns the Niger Delta Development Commission Levy imposed to fund the
sustainable development of the Niger Delta region, the HCDF Levy, which concerns the Nigerian Content Development Fund and other costs
incurred in Nigeria.
Opex/boe (1)
Opex/boe is a non-GAAP measure which represents production costs on a per barrel of oil equivalent basis (using entitlement production). This
allows the Company to better analyze performance against prior periods on a comparable basis. The most direct financial statement measure is
production costs. Entitlement production is calculated using the economic interest methodology and includes cost oil, profit oil and royalty oil
and is different from WI production that is calculated based on project volumes multiplied by the effective WI in each Block.
Three months ended Years ended
Unit
December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
Cost of operations $’m 34.7 35.7 151.7 146.1
Entitlement production MMboe 2.9 3.6 12.8 14.2
Opex/boe $/boe 12.0 9.9 11.9 10.3
(1) Cost of operations and entitlement production have been reported for the year 2025 and 2024 on a constructed financial information basis.
Opex/boe increased in Q4 2025 compared to Q4 2024 primarily from lower entitlement production and in 2025 compared to 2024 primarily
from lower entitlement production and higher cost of operations.
Entitlement production is used as the denominator as production costs include carry of costs that are recovered through entitlement production.
Cost of operations mainly relate to lifting costs from personnel, material and services from third parties.
===== SIDA 24 =====
Report to Shareholders | December 31, 2025
PAGE 15
BUSINESS UPDATE - CONTINUED
Cash flow from operations
Cash flow from operations before working capital is a non-GAAP measure. This represents cash generated by removing the impact from working
capital from cash generated by operating activities and is a measure commonly used to better understand cash flow from operations across
periods on a consistent basis and when viewed in combination with the Company’s results provides a more complete understanding of the
factors and trends affecting the Company’s performance. A reconciliation from cash flow from operations to cash flow from operations before
working capital is shown below:
Three months ended Years ended
$’m
December 31,
2025
December 31,
2024 (1)
December 31,
2025 (1)
December 31,
2024 (1)
Cash flow from operations 79.1 n/a 347.6 n/a
Working capital adjustments included in cash flow from
operations (60.4) n/a (85.8) n/a
Cash flow from operations before working capital 18.7 n/a 261.8 n/a
(1) Cash flow from operations has been reported for the year 2025 only on a constructed financial information basis.
Free cash flow and Free cash flow/boe
Free cash flow is a non-GAAP measure. This measure represents cash generated after costs, and is a measure commonly used to assess the
Company’s profitability.
Free cash flow/boe is a non-GAAP ratio which represents free cash flow on a per barrel of oil equivalent basis using entitlement production
which allows the Company to better analyze performance against prior periods on a comparable basis. Entitlement production is calculated
using the economic interest methodology and includes cost oil, profit oil and royalty oil and is different from WI production that is calculated
based on project volumes multiplied by the effective WI in each Block.
A reconciliation from total cash flow (a GAAP measure) to free cash flow (a non-GAAP measure) is shown below:
Three months ended Years ended
Unit
December 31,
2025
December 31,
2024 (1)
December 31,
2025 (1)
December 31,
2024 (1)
Total cash flow $’m (2.0) n/a (286.2) n/a
Add back dividends paid to shareholders $’m 25.0 n/a 100.2 n/a
Add back repurchase of share capital $’m - n/a 8.3 n/a
Add back debt service costs (2) $’m 36.9 n/a 466.3 n/a
Free cash flow $’m 59.9 n/a 288.6 n/a
Entitlement production MMboe 2.9 n/a 12.8 n/a
Free cash flow/boe $/boe 20.7 n/a 22.5 n/a
(1) Free cash flow and Free cash flow/boe have been reported for the year 2025 only on a constructed financial information basis.
(2) Debt service costs comprise interest payments, repayments and drawdowns of third-party borrowings.
===== SIDA 25 =====
Report to Shareholders | December 31, 2025
PAGE 16
BUSINESS UPDATE - CONTINUED
Tax
The tax expense is made up of the following items:
Three months ended Years ended
$’m
December 31,
2025
December 31,
2024 (1)
December 31,
2025 (1)
December 31,
2024 (1)
Deferred income tax (60.3) (24.5) (106.2) (80.9)
Education tax 5.1 2.1 15.6 14.2
Corporate income tax 36.0 17.1 129.2 130.1
Withholding tax on dividends 12.0 15.0 36.5 22.5
Capital gains tax - 33.0 - 33.0
Petroleum Profit Tax - - - (2.3)
Other taxes 2.3 1.5 2.3 3.9
Total tax (4.9) 44.2 77.4 120.5
(1) Tax has been reported for the year 2025 only on a constructed financial information basis.
In Q4 2025, there was a tax credit. This is from a release of the deferred tax liability as a result of the non-cash impairment recognized to the
Agbami CGU.
Education tax is imposed on every Nigerian company at a rate of 3.0% of the assessable profit in the period.
Corporate income tax is imposed at a rate of 30.0% of the assessable profits in Nigeria in the period.
Petroleum Profit Tax is a tax on the income of companies engaged in upstream petroleum operations in Nigeria. Since operating under the new
PIA terms following conversion during 2023, the leases and licenses are no longer subject to PPT.
Other taxes relates to the Naseni (National Agency for Science and Engineering Infrastructure) Levy that is imposed in Nigeria based on 0.25%
of profits before tax and the Police Fund Levy that is imposed in Nigeria based on 0.005% of net profit.
From January 1, 2026, a new 4% Development Levy on assessable profits is being introduced which will replace Education tax and the Naseni
Levy.
Capital expenditure
Capital expenditure is made up of the following items:
Three months ended Years ended
$’m
December 31,
2025
December 31,
2024 (1)
December 31,
2025 (1)
December 31,
2024 (1)
Nigeria 17.3 n/a 93.8 n/a
Equatorial Guinea 2.8 n/a 6.6 n/a
South Africa (0.3) n/a (0.2) n/a
Total capex 19.8 n/a 100.2 n/a
(1) Capital expenditure has been reported for the year 2025 only on a constructed financial information basis.
Capital expenditure in Q4 2025 and 2025 in Nigeria mainly related to planned infill drilling on Egina and Akpo plus facilities costs on Agbami.
Net Debt
Net Debt is a non-GAAP measure. Net Debt is calculated as loans and borrowings less cash and cash equivalents.
Years ended
As at/ $’m
December 31,
2025
December 31,
2024
Loans and borrowings 330.0 750.0
Cash and cash equivalents (174.7) (460.9)
Net Debt 155.3 289.1
As at December 31, 2025, the Company has $174.7 million of cash and cash equivalents and $330.0 million of debt (as at December 31, 2024
- $460.9 million of cash and cash equivalents and $750.0 million of debt). During 2025, the Company repaid $420.0 million under its RBL facility
reducing outstanding debt to $330.0 million. RBL facility headroom of $138.4 million at the end of 2025.
===== SIDA 26 =====
Report to Shareholders | December 31, 2025
PAGE 17
BUSINESS UPDATE - CONTINUED
EBITDAX and Net Debt/EBITDAX
EBITDAX is a non-GAAP measure. This is used as a performance measure to understand the financial performance from the Company’s business
operations without including the effects of the capital structure, tax rates, DD&A, impairment expenses, unrealized results on commodity risk
management contracts and by adding back realized results on commodity risk management contracts. A reconciliation from total profit (a GAAP
measure) to EBITDAX (a non-GAAP measure) is shown below.
Net Debt/EBITDAX is a non-GAAP measure. Net Debt divided by EBITDAX is a measure of leverage.
Three months ended Years ended
$’m
December 31,
2025
December 31,
2024
December 31,
2025 (1)
December 31,
2024
Total profit/ (loss) (90.8) n/a (82.7) n/a
Add back:
Tax (4.9) n/a 77.4 n/a
Finance costs 12.5 n/a 69.1 n/a
Finance income (0.5) n/a (6.5) n/a
Impairment charges 105.3 n/a 105.3 n/a
Depletion, depreciation and amortization costs 53.3 n/a 280.3 n/a
Commodity risk management contracts (2.2) n/a (2.2) n/a
EBITDAX 72.7 n/a 440.7 n/a
Net Debt 155.3 n/a
Net Debt/EBITDAX 0.4 n/a
(1) EBITDAX and Net Debt/EBITDAX have been reported for the year 2025 only on a constructed financial information basis.
Crude Oil Marketing
In considering cargo liftings, the reader should note that the timing and the frequency of these can vary based on a number of factors such
as reservoir performance; actual realized oil price; capex; opex; underlift/overlift positions and marine logistics. The revenue numbers reported
include cost oil, profit oil and royalty oil where relevant for each field.
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. The average cargo size lifted is one million barrels of oil.
Oil sales were comprised of the following:
Three months ended Years ended
Oil Sales Unit
December 31,
2025
December 31,
2024
December 31,
2025 (1)
December 31,
2024 (1)
Gross crude oil sales
Quantity in Mboe Mboe 3,002.3 - 11,965.5 9,012.8
Average sales price $/bbl 64.4 - 72.2 84.6
Average Bloomberg Dated Brent for the period $/bbl 63.7 - 69.1 82.7
(1) Oil sales have been reported for the year 2025 and 2024 on a constructed financial information basis.
The Company sold 3 cargoes during Q4 2025 at a price of $64.4/bbl.
===== SIDA 27 =====
Report to Shareholders | December 31, 2025
PAGE 18
BUSINESS UPDATE - CONTINUED
Hedging
The Group’s cash flow is exposed to fluctuations in the oil price. A decrease in oil price will lead to a reduction in oil revenue, and vice versa, but
this is offset by an opposite movement in sales entitlement, royalties and taxes. The post-tax net entitlement production represents sales that
the Group has physical price exposure.
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 of December 31,
2025, the group has a mix of physical and financial hedges, as per the table below.
H1 2026 breakdown Mbbl
Fixed price
$/bbl
Sold put
$/bbl
Bought put
$/bbl
Sold call
$/bbl
Sold swap
$/bbl
Collar 300 - - 60.00 67.15 -
Fixed Price (Offtake) 2,000 62.09 - - - -
Total 2,300
H2 2026 breakdown Mbbl
Fixed price
$/bbl
Sold put
$/bbl
Bought put
$/bbl
Sold call
$/bbl
Sold swap
$/bbl
Swap 900 - - - - 63.95
Three way put spread 450 - 45.00 60.00 65.78 -
Collar 300 - - 60.00 74.00 -
Total 1,350
Other non-GAAP measures
This MD&A includes non-GAAP measures, non-GAAP ratios and supplementary financial measures as further described herein. These non-
GAAP figures do not have a standardized meaning prescribed by IFRS Accounting Standards and, therefore, may not be comparable with the
calculation of similar measures by other companies. The Company believes that the presentation of these non-GAAP figures provides useful
information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance
against prior periods on a comparable basis.
NIGERIA
Following the amalgamation, the Company has direct interests in three producing fields, three undeveloped discoveries, and number of near-
field exploration opportunities in deepwater Nigeria through four PMLs and two PPLs.
The three producing fields are Akpo (PML 2), Egina (PML 3) and Agbami (PML 52). The primary undeveloped oil discovery is Preowei (PML 4),
which lies to the north of Egina and Akpo fields and is planned to be developed through a subsea tie-back development to the Egina FPSO.
The other two undeveloped discoveries are Egina South (PPL 261), which lies to the southwest of Egina and Akpo fields, and the Ikija discovery
(PPL 2003), which lies to the west of Agbami. The Company’s assets are located in the deepwater area of the Niger Delta more than 100 km
offshore Nigeria.
Please refer to pages 17 - 18 of the Company’s Annual Information Form (“AIF”) for the Year Ended December 31, 2025, for the detailed
commercial information, and pages 39 - 48 of the same document for the detailed technical information on these assets. The AIF is available on
SEDAR+ at www.sedarplus.ca or on the Company’s website at www.mereninc.com.
BLOCK 3B/4B – SOUTH AFRICA
Meren, through a wholly-owned subsidiary, holds an 18.0% interest in Block 3B/4B, which lies in the Orange Basin. The Block 3B/4B legislative
notification and appeals process is currently suspended pending a Supreme Court of Appeal judgment in respect of Block 5/6/7. The operator
of Block 3B/4B currently plans to drill the first exploration well as soon as the Environmental Authorization is confirmed.
Please refer to the Company’s AIF for the year-ended December 31, 2025, for further details on Block 3B/4B.
BLOCKS EG-18 AND EG-31 – EQUATORIAL GUINEA
The Company, through wholly-owned subsidiaries, holds an operated WI of 80.0% in each of Blocks EG-18 and EG-31, offshore Equatorial Guinea.
On December 17, 2025, the Company received notification from the Ministry of Hydrocarbons and Mining Development in Equatorial Guinea
approving extensions of up to two years to the first exploration sub period on each block.
During Q4 2025 the Company continued dialogue with potential partners during its active data room process across both blocks and progressed
discussions with the government and GEPetrol on forward plans with the aim of forming joint ventures capable of planning exploration drilling
as early as late 2026 or 2027.
Please refer to the Company’s AIF for the year-ended December 31, 2025, for further details on Blocks EG-18 and EG-31.
===== SIDA 28 =====
Report to Shareholders | December 31, 2025
PAGE 19
BUSINESS UPDATE - CONTINUED
EQUITY INVESTMENTS IN ASSOCIATES
As at December 31, 2025, the Company held equity investments in two oil and gas companies, which provides exposure to several high-impact
exploration drilling prospects in South Africa and Namibia.
The Company held the following equity investments in associates as of December 31, 2025:
Africa Energy Impact (1)
Issued and Outstanding 479,162,450 1,139,147,442
Shares held by Meren at December 31, 2024 55,396,483 449,464,396
Shares acquired in the period - -
Shares held by Meren at December 31, 2025 55,396,483 449,464,396
Meren’s holding (%) – December 31, 2025 11.56% 39.46%
Meren’s holding (%) – December 31 2024 19.67% 39.46%
Share price (CAD) on December 31, 2025 0.11 -
Exchange rate to USD on December 31, 2025 0.73 -
(1) Impact is a privately held UK company and no share price is available.
Impact
Impact is a private UK oil and gas exploration company with assets located offshore Namibia and South Africa. Please refer to the Company’s
AIF for the year-ended December 31, 2025, for further details on the Company’s shareholding in Impact and the supplementary technical and
commercial information.
The Company through its 39.5% shareholding in Impact Oil & Gas Limited has an effective 3.8% interest in Blocks 2912 and 2913B, offshore
Namibia, with the latter block containing the Venus light oil discovery. The blocks are operated by a subsidiary of TotalEnergies. Under Impact’s
carried-interest arrangement with TotalEnergies, Meren’s exposure to all development and exploration costs on Blocks 2912 and 2913B
remains fully funded through to first commercial production, without any financial cap.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE
Following the amalgamation, the Company reiterates its commitment to be a responsible owner and operator, integrating sustainability
considerations throughout its decision-making processes to support Company commercial objectives.
During 2025 there were no reported material HSEC incidents.
GHG emissions during the reporting period were in line with operational forecasts. Further details will be set out in the Company’s annual
Sustainability Report.
Activities continue on the Company’s development assets with no material developments to be reported during the reporting period. The Block
3B/4B legislative notification and appeals process is currently suspended pending a Supreme Court of Appeal judgment in respect of Block
5/6/7.
The Company’s 2024 Sustainability Report, published on May 12, 2025, is disclosed on the Company website, as with previous reports it contains
more detailed information on the Company’s performance and strategy related to sustainability matters. The Company’s 2025 Sustainability
Report will be published on the Company’s website during the first half of 2026.
===== SIDA 29 =====
Report to Shareholders | December 31, 2025
PAGE 20
SELECTED ANNUAL INFORMATION
For the years ended
December 31,
2025
December 31,
2024
December 31,
2023
Statement of Net Income or Loss and Other Comprehensive Income or Loss:
Revenue 562.1 - -
Net (loss)/ income attributable to common shareholders ($’m) (31.6) (279.1) 87.1
Data per Common Share:
Basic income/(loss) per share ($/share) (0.05) (0.62) 0.19
Diluted income/(loss) per share ($/share) (0.05) (0.62) 0.18
Balance Sheet:
Financial liabilities ($’m) 333.8 3.3 -
Total assets ($’m) 1,951.9 615.2 966.2
Cash dividends (per share basis) 0.1484 0.05 0.05
In 2025, the Company recorded revenue, mainly related to oil sales, following the amalgamation with Meren Coop. In 2024 and 2023, the
Company held a 50% investment in Meren Coop, accounted for as a Joint Venture and therefore no revenue was recognized in these years.
In 2025, the Company recorded a net loss attributable to common shareholders of $31.6 million and a net loss of $279.1 million in 2024.
In 2025, the Company fully consolidated Meren Coop and partly reversed impairment on its investment in joint venture when the Company
completed the transaction with BTG Oil & Gas to consolidate its interest in Meren Coop on March 19, 2025, and the loss was primarily from
anon-cash impairment of $105.3 million to the Agbami CGU. In 2024, the Company recorded a net loss attributable to common shareholders of
$279.1 million which is a decrease from the net income of $87.1 million recorded in 2023. In 2024, this was primarily made up of income from
the Company’s investment in Meren Coop of $226.0 million offset against losses from the Company’s investment in associates of $38.7 million
and an impairment in the Company’s investment in Meren Coop of $436.7 million as the fair value of the Company’s existing shareholding in
Meren Coop was calculated based on the implied value of the Proposed Reorganization, which was in excess of the carrying value resulting in a
non-cash impairment loss on the investment in Meren Coop.
In 2025, the basic and diluted loss per share was $0.05 (2024 – basic and diluted loss per share of $0.62). The loss per share in 2025 has arisen
from a non-cash impairment recognized to oil and gas properties related to the Agbami CGU. In 2024, the basic and diluted loss per share was
$0.62 (2023 – the basic income per share was $0.19 and the diluted income per share was $0.18). The loss per share has arisen primarily from
the impairment recognized to the Company’s investment in Meren Coop.
In 2025, the increase to financial liabilities is mainly from the RBL facility held by Meren Coop, which is now consolidated in the Group’s balance
sheet. In 2024, the increase to financial liabilities related to a lease liability recognized for lease of an office building.
In 2025, total assets have increased following the amalgamation and recognition of oil and gas interests in the Groups operations in Nigeria. In
2024 the decrease in total assets is primarily due to the decrease in cash balances and the decrease to the Company’s investment in Meren
Coop from the impairment recognized.
===== SIDA 30 =====
Report to Shareholders | December 31, 2025
PAGE 21
SUMMARY OF QUARTERLY INFORMATION
All financial information included in the narrative discussion below is based on the Consolidated Statement of Net Income or Loss and Other
Comprehensive Income or Loss and considers the amalgamation closing on March 19, 2025.
Summarized quarterly results for the past eight quarters are as follows:
For the three months ended
31-Dec
2025
30-Sep
2025
30-Jun
2025
31-Mar
2025
31-Dec
2024
30-Sep
2024
30-Jun
2024
31-Mar
2024
Revenue 199.7 216.7 69.3 76.4 - - - -
Net (loss)/ income attributable to
common shareholders ($’m) (90.8) 5.2 3.1 50.9 6.2 (289.2) 0.4 3.5
Weighted average shares – Basic ‘000 675,686 675,513 675,012 468,472 442,690 442,960 451,231 460,991
Weighted average shares – Diluted
‘000 675,686 682,770 682,039 476,836 449,667 442,960 464,890 474,746
Basic (loss)/ income per share ($) (0.13) 0.01 0.00 0.11 0.02 (0.65) 0.00 0.01
Diluted (loss)/ income per share ($) (0.13) 0.01 0.00 0.11 0.02 (0.65) 0.00 0.01
SUMMARY OF KEY ITEMS OF FINANCIAL PERFORMANCE IN THE YEARS ENDED DECEMBER 31, 2025, AND
DECEMBER 31, 2024
Three months ended Years ended
December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
Revenue 199.7 - 562.1 -
Gross (loss)/ profit (78.2) - 36.0 -
General and administrative expenses (5.0) (13.3) (36.4) (32.4)
Net (loss)/ income (90.8) 6.2 (31.6) (279.1)
Revenue
Revenue generated in Q4 2025 and 2025 was $199.7 million and $562.1 million respectively (Q4 2024 and 2024 – nil) and primarily related
to 3 cargoes sold in Q4 2025 at an average price of $64.4/bbl and 5 additional cargoes sold in the period post amalgamation to the end of Q3
2025 at an average price of $70.4/bbl. Prior to the closing of the amalgamation on March 19, 2025, the Company did not report any revenue
in its Consolidated Statement of Net Income or Loss and Other Comprehensive Income or Loss.
Gross profit
Gross loss reported in Q4 2025 and gross profit in 2025 was $78.2 million and $36.0 million respectively (Q4 2024 and 2024 – nil). Gross profit
was impacted by costs of sales in Q4 2025 and 2025 of $277.9 million and $526.1 million respectively (Q4 2024 and 2024 – nil) and mainly
comprised of non-cash impairment charges of $105.3 million to oil and gas properties related to the Agbami CGU, depletion costs of $52.9
million and $207.9 million respectively, net overlift movements of $63.4 million and $46.3 million respectively, and costs of operations of $34.7
million and $114.3 million respectively.
===== SIDA 31 =====
Report to Shareholders | December 31, 2025
PAGE 22
General and administrative costs
On March 19, 2025, the Company announced the completion of the amalgamation to acquire the remaining 50% interest in Meren Coop in
exchange for 239,828,655 newly issued common shares in Meren. This transaction falls under IFRS 3 under which acquisition related costs are
expensed in the periods in which the costs are incurred, and the services are received.
The table below shows adjusted general and administrative expenses, which is a non-GAAP measure, by excluding the BTG Oil & Gas transaction
related expenses and is meant to improve comparability between periods. The BTG Oil & Gas transaction related expenses also include certain
LTIP charges for fully vested LTIP units as a result of the closing of the amalgamation.
Three months ended Years ended
December 31,
2025
December 31,
2024
December 31,
2025
December 31,
2024
General and administrative expenses 5.0 13.3 36.4 32.4
BTG Oil & Gas transaction related expenses - (0.7) (9.0) (6.9)
Adjusted general and administrative expenses 5.0 12.6 27.4 25.5
Adjusted general and administrative expenses, including share-based compensation charges relating to the LTIP and Stock Option Plan that are
not impacted by the closing of the amalgamation, in Q4 2025 and 2025 amounted to $5.0 million and $27.4 million respectively (Q4 2024 and
2024 - $12.6 million and $25.5 million respectively). Share-based compensation charges not impacted by the closing of the amalgamation in
Q4 2025 and 2025 amounted to $1.4 million and $3.7 million respectively (Q4 2024 and 2025 – $0.2 million and $1.5 million respectively) are
impacted by movements in the share price of the Company and performance conditions.
Adjusted general and administrative expenses excluding share-based compensation charges amounted to $3.6 million in Q4 2025 compared
to $12.4 million in Q4 2024. The decrease is mainly driven by cost allocations since closing of the amalgamation with these cost allocations
reflected in Q4 2025.
Adjusted general and administrative expenses excluding share-based compensation charges amounted to $23.7 million in 2025, which is in line
with 2024 amounting to $24.0 million.
SUMMARY OF KEY ITEMS OF FINANCIAL POSITION AS AT DECEMBER 31, 2025, AND DECEMBER 31, 2024
As at
December 31,
2025
December 31,
2024
Assets
Oil and gas properties 1,413.5 -
Intangible exploration assets 43.7 29.3
Equity investments in associates 142.2 177.6
Cash and cash equivalents 174.4 61.4
Outstanding bank debt 330.0 -
Oil and gas properties
Oil and gas properties have increased following closing of the amalgamation to acquire the remaining 50% interest in Meren Coop following
which Meren Coop is fully consolidated by the Company.
As at December 31, 2025, oil and gas properties amounted to $1,413.5 million (as at December 31, 2024 – nil) 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.
Intangible exploration assets:
As at December 31, 2025, the carrying amount of the Company’s intangible exploration assets in Equatorial Guinea was $24.5 million (as at
December 31, 2024 – $17.9 million) and related to its 80% interest in Blocks EG-18 and EG-31.
As at December 31, 2025, the carrying amount of the Company’s intangible exploration assets in South Africa was $19.2 million (as at
December 31, 2024 - $11.4 million) and related to its 18.0% (as at December 31, 2024 – 17.0%) participating interest in the Block 3B/4B
Exploration Right.
Equity investments in associates
As at December 31, 2025, the Company’s investment in associates was $142.2 million compared to an investment value of $177.6 million
as at December 31, 2024. The carrying value of the investments decreased by $35.4 million in 2025 mainly from the Company’s share of
the associates losses of $2.9 million in combination with a distribution by Impact of $31.6 million net to the Company’s shareholding. The
investment in Impact, holding the working interests in the Namibia Orange Basin Blocks 2913B and 2912, makes up $140.7 million of the total
equity investments in associates.
SUMMARY OF QUARTERLY INFORMATION - CONTINUED
===== SIDA 32 =====
Report to Shareholders | December 31, 2025
PAGE 23
Cash and cash equivalents
Cash and cash equivalents have increased following closing of the amalgamation to acquire the remaining 50% interest in Meren Coop following
which Meren Coop is fully consolidated by the Company. As at December 31, 2025, the Company had $174.7 million cash and cash equivalents
on hand, compared to a cash balance of $61.4 million as at December 31, 2024. The Company acquired cash balances on closing date of the
amalgamation of $380.4 million, the Company received a distribution from Meren Coop of $60.0 million prior to the closing of the amalgamation,
repaid $420.0 million of the RBL facility, returned $108.5 million to shareholders by way of dividends and share buybacks, received a distribution
from Impact of $31.6 million, incurred capital and operational expenditure in respect of the licenses in Nigeria, Equatorial Guinea and South
Africa, settled working capital balances and incurred general and administrative costs.
Outstanding bank debt
Outstanding bank debt increased following closing of the amalgamation to acquire the remaining 50% interest in Meren Coop following which
Meren Coop is fully consolidated by the Company. Subsequent to closing of the amalgamation, the Company cancelled its corporate facility,
repaid $420.0 million under the RBL facility, reducing outstanding bank debt to $330.0 million as at December 31, 2025. RBL facility headroom
of $138.4 million at the end of 2025.
LIQUIDITY AND CAPITAL RESOURCES
As at December 31, 2025, the Company had cash balances of $174.7 million and net working capital balances (including cash balances) of $18.9
million negative. Net working capital is calculated as current assets less current liabilities as presented in the consolidated balance sheet as per
December 31, 2025. The Company’s primary source of liquidity is operating income in Nigeria and the remaining undrawn amounts on the RBL.
Reserves Based Lending Facility
Meren has a Reserves Based Lending Facility (“RBL”) in place with $800.0 million in commitments from the date of the amalgamation. 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. 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 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 and 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.
All financial and liquidity covenants covered by the RBL are restricted to these three entities. The 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 three months ended 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.
Future Funding Outlook
To finance its future acquisition, exploration, development and operating costs, the Company may require financing from external sources,
including issuance of new shares, issuance of debt or executing farmout or disposition arrangements. There can be no assurance that such
financing will be available to the Company or, if available, that it will be offered on terms acceptable to the Company.
The Company believes that its existing cash balances combined with anticipated funds flow from its operations and undrawn facilities will
provide sufficient liquidity for the Company to meet its financing, operating and capex commitments as they fall due.
===== SIDA 33 =====
Report to Shareholders | December 31, 2025
PAGE 24
OUTSTANDING SHARE DATA
The following table outlines the maximum potential impact of share dilution upon full execution of outstanding convertible instruments as at
the effective date of the MD&A.
Common shares outstanding 675,909,193
Outstanding share purchase options 22,616
Outstanding restricted share units 1,368,733
Outstanding performance share units 10,992,194
Full dilution impact on Common Shares outstanding 688,292,736
RELATED PARTY TRANSACTIONS
Transactions with Africa Energy:
On December 19, 2022, Africa Energy announced that it had secured a $5.0 million promissory note of which $2.0 million was provided by the
Company and the remaining by other parties. On November 7, 2023, the promissory note provided by the Company and other parties to Africa
Energy was increased by $3.3 million with $1.5 million of the increase provided by the Company by the end of the year ended December 31,
2024. No funds were provided during 2025, and $0.8 million was provided in the year ended December 31, 2024. The note was unsecured and
matured on March 31, 2025, when the principal and accrued interest was repaid by Africa Energy in full. The note carried an annual interest
rate of 15%. In the three months ended March 31, 2025, interest on the note amounted to $0.2 million (year ended December 31, 2024 - $0.5
million).
Transactions with 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, 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. Meren will benefit from the carry agreed between Eco, TotalEnergies and QatarEnergy for this incremental interest.
Transactions with Impact:
On January 29, 2025, Impact distributed $31.6 million net to the Company’s shareholding.
Transactions with BTG Oil & Gas:
The Company has recorded 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).
Remuneration of Directors and Senior Management:
Remuneration of Non-Executive Directors and Senior Management includes all amounts earned and awarded to the Company’s Board of
Directors and Senior Management. Senior Management includes the Company’s President and Chief Executive Officer, Chief Financial Officer,
Chief Commercial and Operations Officer, Chief Operating Officer (position removed in 2025), Chief Technical Officer (position removed in
2025), Chief Legal Officer and Chief Human Resources Officer.
Directors’ fees include Board and Committee Chair retainers. Management’s short-term wages and benefits include salary, benefits, bonuses and
any other cash-based compensation earned or awarded during the year. Share-based compensation includes expenses related to the Company’s
share purchase option plan as well as the Long-Term Incentive Plan.
For the years ended
December 31,
2025
December 31,
2024
Non-Executive Directors' fees 0.7 0.5
Non-Executive Directors' share-based compensation 1.4 0.6
Managements’ short-term wages and benefits 7.1 7.3
Managements’ share-based compensation 3.5 0.5
12.7 8.9
===== SIDA 34 =====
Report to Shareholders | December 31, 2025
PAGE 25
COMMITMENTS AND CONTINGENCIES
The following commitments and contingencies are representative of the Company’s net obligations at the effective date of the MD&A.
MEREN COÖPERATIEF U.A:
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.
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 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.
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.
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 $154.6 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.
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.
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Report to Shareholders | December 31, 2025
PAGE 26
CRITICAL ACCOUNTING ESTIMATES
The Company’s critical accounting estimates are defined as those estimates that have a significant impact on the portrayal of its financial
position and operations and that require management to make judgements, assumptions and estimates in the application of IFRS Accounting
Standards. Judgements, assumptions and estimates are based on historical experience and other factors that management believes to be
reasonable under current conditions. As events occur and additional information is obtained, these judgements, assumptions and estimates may
be subject to change.
USE OF ESTIMATES
The preparation of the consolidated financial statements in conformity with IFRS Accounting Standards requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the
date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Such estimates
include unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ
from these estimated amounts as future confirming events occur. Significant estimates used in the preparation of the consolidated financial
statements include, but are not limited to, recovery of exploration costs capitalized in accordance with IFRS Accounting Standards, equity
method accounting, valuation and impairment of equity investments and contingent consideration arising from the acquisition of Meren Coop.
The Company’s material accounting policies can be found in the Company’s audited consolidated financial statements for the years ended
December 31, 2024, and December 31, 2025.
CLASSIFICATION OF JOINT ARRANGEMENTS
The Group is a party to 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.
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;
● 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.
===== SIDA 36 =====
Report to Shareholders | December 31, 2025
PAGE 27
CRITICAL ACCOUNTING ESTIMATES - CONTINUED
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.
CONSOLIDATION OF ENTITIES
When assessing control over a subsidiary, the Company is required to consider the nature of its relationship with the subsidiary, and whether
strategic and operating decisions made by the subsidiary are made independently without the significant influence or control of the Company.
Factors considered when assessing for control include share ownership, board composition and management involvement in the business. The
determination of whether strategic and operating decisions made by the Company’s subsidiaries (see note 27) are made independently without
the significant influence or control of the Company requires judgement.
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
petroleum reserves, future commodity prices, operating and capital costs as well as discount rates. The proved and probable petroleum 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.
IMPAIRMENT OR REVERSAL OF 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
===== SIDA 37 =====
Report to Shareholders | December 31, 2025
PAGE 28
CRITICAL ACCOUNTING ESTIMATES - CONTINUED
HYDROCARBON RESERVE AND RESOURCE ESTIMATES
Oil and gas production assets, including facilities, are depreciated 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 the principles contained in the SPE Petroleum Resources
Management Reporting System (“PRMS”) framework.
The Company estimates its 2P reserves based on information provided by reputable independent petroleum engineers, through the information
provided by the respective operators. This information from reputable independent petroleum engineers concerns, amongst others, the
geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery
rates.
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 current long-term Brent oil price assumption used in the estimation of proved and probable reserves is based on the IQRE 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.
UNITS-OF-PRODUCTION DEPRECIATION OF OIL AND GAS PROPERTIES
Oil and gas properties are depreciated using the UoP-method over total estimated proved and probable hydrocarbon 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 reserves, or future capital expenditure estimates change.
Changes to proven and probable reserves could arise due to changes in the factors or assumptions used in estimating reserves, including the
effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions or unforeseen
operational issues.
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
===== SIDA 38 =====
Report to Shareholders | December 31, 2025
PAGE 29
PROVISION FOR SITE RESTORATION
Amounts used in recording a provision for site restoration are based on current legal and constructive requirements and current technology
and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future
cash outflows in relation to the site decommissioning and restoration can be difficult. 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).
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.
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.
Assumptions about the generation of future taxable profits depend on management’s estimates of future cash flows. These estimates of future
taxable income are based on forecast cash flows from operations (which are impacted by production and sales volumes, oil and gas prices,
reserves, production costs, decommissioning costs, capital expenditure, dividends and other capital management transactions) and judgement
about the application of existing tax laws in each jurisdiction.
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.
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).
GOING CONCERN
The 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.
CRITICAL ACCOUNTING ESTIMATES - CONTINUED
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Report to Shareholders | December 31, 2025
PAGE 30
INTERNAL FINANCIAL REPORTING AND
DISCLOSURE CONTROLS
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company
in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and
reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information
required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted under securities legislation is
accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate
to allow timely decisions regarding required disclosure. Due to the amalgamation discussed above completed on March 19, 2025, the Company’s
disclosure controls and procedures have been updated to reflect the amalgamated disclosure controls and procedures.
Management, including the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of
the Company’s disclosure controls and procedures. As of December 31, 2025, the Chief Executive Officer and Chief Financial Officer have each
concluded that the Company’s disclosure controls and procedures, as defined in NI 52-109 - Certification of Disclosure in Issuer’s Annual and
Interim Filings, are effective to achieve the purpose for which they have been designed.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
Internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements in accordance with IFRS Accounting Standards. Management is also responsible for the design of the
Company’s internal control over financial reporting in order to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with IFRS Accounting Standards.
The Company’s internal controls over financial reporting include policies and procedures that: pertain to the maintenance of records that, in
reasonable detail accurately and fairly reflect the transactions and disposition of assets; provide reasonable assurance that transactions are
recorded as necessary to permit preparation of the financial statements in accordance with IFRS Accounting Standards and that receipts and
expenditures are being made only in accordance with authorization of management and directors of the Company; and provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect
on the financial statements. Due to the amalgamation discussed above completed on March 19, 2025, the Company’s disclosure controls and
procedures have been updated to reflect the amalgamated disclosure controls and procedures.
Management, including the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of
the Company’s internal controls over financial reporting. As at December 31, 2025, the Chief Executive Officer and Chief Financial Officer have
each concluded that the Company’s internal controls over financial reporting, as defined in NI 52-109 - Certification of Disclosure in Issuer’s
Annual and Interim Filings, are effective to achieve the purpose for which they have been designed. Because of their inherent limitations,
internal controls over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Furthermore,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes
in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
ADVISORY REGARDING OIL AND GAS
INFORMATION
The terms boe (barrel of oil equivalent) and MMboe (millions of barrels of oil equivalent) are used throughout this report. Such terms may
be misleading, particularly if used in isolation. The conversion ratio of six thousand cubic feet per barrel (6 Mcf:1 Bbl) of conventional natural
gas to barrels of oil equivalent and the conversion ratio of 1 barrel per six thousand cubic feet (1 Bbl:6 Mcf) of barrels of oil to conventional
natural gas equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to conventional natural gas
is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
In this report, references are made to historical and potential future oil production in Nigeria and Namibia. In all instances these references are
to light and medium crude oil category in accordance with NI 51-101 and the COGE Handbook.
Reserves are estimated remaining quantities of petroleum anticipated to be recoverable from known accumulations, as of a given date, based on
the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which
are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates
and may be sub-classified based on development and production status. Proved Reserves are those quantities of petroleum, which, by analysis
of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward,
from known reservoirs and under existing economic conditions, operating methods and government regulations. Probable Reserves are those
additional quantities of petroleum that are less certain to be recovered than Proved Reserves, but which, together with Proved Reserves, are as
likely as not to be recovered. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is
unlikely that actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
===== SIDA 40 =====
Report to Shareholders | December 31, 2025
PAGE 31
RISK FACTORS
With Board oversight, the Company proactively manages the identification, assessment and mitigation of risks, many of which are common to
operations in the oil and gas industry as a whole, whilst others are unique to the Company. The realization of any of the risks listed below could
have a material adverse effect on the Company’s business, financial condition, reserves and results of operations, such list being non-exhaustive.
Risks that can materially affect the figures presented and disclosed in the Financial Statement and MD&A are described in the Company’s
Annual Information Form for the year ended December 31, 2025 (”AIF”) available on SEDAR+ at www.sedarplus.ca or on Meren’s website at
www.mereninc.com/investor-summary/financial-reports-meetings-filings/.
The risks noted in the risk factors section comprises those that can materially affect the figures presented and disclosures in the Financial
Statements and MD&A. The Company’s Annual Information Form contains a more comprehensive list of risks that can affect the Company.
PRICES, MARKETS AND MARKETING OF CRUDE OIL AND NATURAL GAS
Crude oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are
beyond the control of the Company. World prices for oil and gas have fluctuated widely in recent years. Any material decline in prices could have
an adverse effect on the Company’s business and prospects. The Company may be required by government authorities to limit production due
to OPEC+ quotas from time to time. The conflicts in Ukraine and the Middle East have impacted global markets and may continue to result in
increased volatility in financial markets and commodity prices. The Company does not have a direct exposure to operations in Ukraine and the
Middle East.
The Company may undertake hedging activities when efficient to do so, however, hedging may not fully mitigate, in whole or in part, the risk and
effect of lower commodity prices or may limit upside in rising markets.
The Company or its investee company’s ability to market its oil and gas may depend upon its ability to acquire space on vessels or in pipelines
that deliver oil and gas to commercial markets. The Company could also be affected by deliverability uncertainties related to the proximity of
its reserves to pipelines and processing and storage facilities and operational issues affecting such pipelines and facilities as well as government
regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and gas and many other aspects of the oil and
gas business.
HEDGING
The Group enters into agreements to receive fixed prices on its oil and gas production to offset the risk of revenue reduction if commodity
prices decline. However, if commodity prices increase beyond the levels set in such agreements, the Group will not benefit from such increases.
LIQUIDITY AND CASH FLOW
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity describes a company’s
ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fulfil their work commitments
in accordance with contractual obligations, and to be able to potentially acquire strategic oil and gas assets and face potentially unexpected
liabilities.
The Company could potentially issue debt or equity, extend its debt maturities and enter into farmout agreements to ensure it has sufficient
available funds to meet current and foreseeable financial requirements.
The Company actively monitors its liquidity to ensure that its cash flows and working capital are adequate to support these financial obligations
and the Company’s capital programs. The Company will also adjust the pace of its activities to manage its liquidity position. Notwithstanding any
mitigation efforts, the Company remains exposed to erosion of its balance sheet and revenues and may have difficulty in securing necessary
funding, which may lead to insufficient liquidity.
CREDIT FACILITIES
The Company is party to credit facilities. The terms of the facility contain covenants and restrictions on the ability of the Company to, among
other things, incur or lend additional debt, pay dividends and make restricted payments, and encumber its assets. The failure of the Company
to comply with the covenants contained in the facility or to repay or refinance the facility by its maturity date could result in an event of
default, which could, through acceleration of debt, enforcement of security or otherwise, materially and adversely affect the operating results
and financial condition of the Company. As disclosed in the Financial Statements, the Company’s revolving reserve-based loan (RBL) amortizes
quarterly to the lower of commitments and the borrowing base assessment and matures on June 20, 2029.
CREDIT RISK
Credit risk is the risk of loss if counterparties do not fulfil their contractual obligations. Most of the Company’s credit exposure relates to
amounts due from its JV parties and receivables from crude oil sales. Sales are predominantly to investment-grade counterparties or supported
by letters of credit/guarantees. A portion of the Company’s cash is held by banks in foreign jurisdictions.
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Report to Shareholders | December 31, 2025
PAGE 32
INTEREST RATE RISK
The Company floating-rate borrowings that reference SOFR and therefore could be exposed to volatility in interest rates that could constrain
the company’s cashflows.
SUBSTANTIAL CAPITAL REQUIREMENTS
Meren expects to make substantial capital expenditures for exploration, development and production of oil and gas reserves in the future. The
Company’s ability to access the equity or debt markets may be affected by any prolonged market instability. The inability to access the equity or
debt markets for sufficient capital, at acceptable terms and within required time frames, could have a material adverse effect on the Company’s
financial condition, results of operations and prospects.
To finance its future acquisition, exploration, development and operating costs, the Company may require financing from external sources,
including from the issuance of new shares, issuance of debt or execution of working interest farmout agreements. There can be no assurance
that such financing will be available to the Company or, if available, that it will be offered on terms acceptable to the Company.
If additional financing is raised through the issuance of equity or convertible debt securities, control of the Company may change and the
interests of shareholders in the net assets of the Company may be diluted. If unable to secure financing on acceptable terms, the Company may
have to cancel or postpone certain of its planned exploration and development activities which may ultimately lead to the Company’s inability
to fulfil the minimum work obligations under the terms of its various concessions. Availability of capital will also directly impact the Company’s
ability to take advantage of acquisition opportunities.
FINANCIAL STATEMENTS PREPARED ON A GOING CONCERN BASIS
Meren’s financial statements have been prepared on a going concern basis under which an entity is considered to be able to realize its assets
and satisfy its liabilities in the ordinary course of business. There can be no assurances that the Company will be successful in completing
additional financings, achieving profitability or completing future transactions.
RISKS INHERENT IN OIL AND GAS EXPLORATION, DEVELOPMENT, AND PRODUCTION
Oil and gas operations involve many risks, which, even with the combination of experience, knowledge and careful evaluation may not be able
to overcome. The long-term commercial success of Meren depends on its ability to find, acquire, develop and commercially produce oil and gas
reserves. No assurance can be given that the Company will be able to locate satisfactory properties for acquisition or participation. Moreover,
if such acquisitions or participations are identified, the Company may determine that current markets, terms of acquisition and participation
or pricing conditions make such acquisitions or participations uneconomic. It is difficult to project the costs of implementing an exploratory,
appraisal or development drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with
encountering various drilling conditions such as over pressured zones, tools lost in the hole, equipment failures or malfunctions and changes in
drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. Without the continual
addition of new reserves, any existing reserves associated with the Company’s oil and gas assets at any particular time, and the production
therefrom, could decline over time as such existing reserves are exploited. There is a risk that additional commercial quantities of oil and gas
may not be discovered or acquired by the Company.
Meren’s business is subject to all the risks and hazards inherent in businesses involved in the exploration for, and the acquisition, development,
production and marketing of, oil and gas, many of which cannot be overcome even with a combination of experience and knowledge and careful
evaluation. The risks and hazards typically associated with oil and gas operations include fire, explosion, blowouts, sour gas releases, pipeline
ruptures and oil spills, each of which could result in substantial damage to oil and gas wells, production facilities, other property, the environment
or personal injury, and such damages may not be fully insurable.
RISKS ASSOCIATED WITH DISCOVERING HYDROCARBONS
While the Company has historically made discoveries, there is no certainty that expenditures made on future exploration or development
activities by Meren will result in discoveries of oil or gas in commercial quantities or that commercial quantities of oil and gas will be discovered,
produced, or acquired by the Company. The portion of the Company’s portfolio, which include prospects & leads require additional data to fully
define their potential and significant changes to the resource estimates will occur with the incorporation of additional data and information.
There is no certainty that any discovered resources will be commercially viable to produce. There is no certainty that any portion of undiscovered
resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
RISK FACTORS - CONTINUED
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Report to Shareholders | December 31, 2025
PAGE 33
RISKS ASSOCIATED WITH RESERVES AND RESOURCES VOLUME ESTIMATES
In the event of a discovery, reservoir parameters, such as porosity, permeability, net hydrocarbon pay thickness, fluid composition and water
saturation, may vary from those assumed by the Company’s independent third-party resource evaluator affecting the volume of hydrocarbon
estimated to be present. Other factors such as the reservoir pressure, density and viscosity of the oil, solution gas/oil ratio, permeability, the
presence or absence of water drive and the specific mineralogy of the reservoir rock will affect the volume of oil that can be recovered. Drill
stem tests, or well tests, are commonly based on flow periods of one to five days and build up periods of one to three days to aid in understanding
reservoir performance. Well test results include uncertainty and are not necessarily indicative of long-term performance or of ultimate recovery.
Furthermore, there are many uncertainties inherent in estimating quantities of oil and natural gas reserves and resources (contingent and
prospective) and the future cash flows attributed to such reserves and resources. The actual production, revenues, taxes and development and
operating expenditures with respect to the reserves and resources associated with the Company’s assets will vary from estimates thereof and
such variations could be material. Estimates of reserves that may be developed and produced in the future are often based upon volumetric
calculations and upon analogy to similar types of reserves rather than actual production history. There is uncertainty that it will be commercially
viable to produce any portion of the contingent resources. Actual future net cash flows will be affected by other factors, such as actual
production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers,
changes in governmental regulation or taxation and the impact of inflation on costs.
RISKS ASSOCIATED WITH PRODUCTION GUIDANCE AND FORECASTING
Production guidance includes uncertainty around reservoir and well performance, reliability of production and process facilities, success of
future drilling programs and execution of planned maintenance activities. Completion of future wells does not ensure a profit on the investment
or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of
operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays
in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage
or transportation capacity or other geological and mechanical conditions. While structured maintenance plans, as well as close well, facility and
operational supervision can contribute to maximizing production rates over time, production delays and declines from field operating conditions
cannot be eliminated and may adversely affect production guidance, revenue and cash flow levels to varying degrees.
RISKS RELATING TO INFRASTRUCTURE
Meren is dependent on having available and functioning infrastructure relating to the properties and licenses on which it operates, such as roads,
power and water supplies, pipelines and gathering systems, supply bases and associated services.
The amount of oil and gas that the Company can produce, and sell is subject to accessibility, availability, proximity and capacity of gathering,
processing and pipeline systems. The lack of availability of capacity or a failure in any of the gathering, processing and pipeline systems, and in
particular the processing facilities could result in the Company’s inability to realize the full economic potential of its production or in a reduction
of the price offered for the Company’s production. Any significant change in market factors, terms of use or other conditions affecting these
infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm the Company’s
business financial condition, results of operations, cash flows and future prospects.
In Nigeria, gas export relies on the continued safe operations at the Nigeria LNG facility. Gas export restrictions could have an adverse effect on
oil production, due to reductions in overall facility production to minimise flaring of associated gas. The supply chain for offshore is dependent
upon existing ports and onshore infrastructure. Several factors, including social unrest onshore, have the potential to disrupt both the gas
processing facilities and the upstream supply chain which could have detrimental impacts on cashflows.
In Equatorial Guinea, exploration efforts in Block EG-31 are targeting gas prospects located close to existing gas export and processing facilities.
In the event of a discovery, the discovered fluids may not be compatible with the existing processing facilities resulting in additional cost which
may result in the potential discovery being non-commercial. There may also be insufficient ullage in the facilities to accept additional capacity
and without appropriate commercial arrangements it may not be possible to produce any potential discovery.
RISKS ASSOCIATED WITH THE AVAILABILITY OF EQUIPMENT AND STAFF
Meren’s oil and gas exploration and development activities are dependent on the availability of drilling and related equipment and qualified staff
in the particular areas where such activities are or will be conducted. For any operated drilling or seismic activities, the Company would rely on
the availability of leased drilling rigs or seismic equipment used for its exploration and development activities. Shortages of such equipment or
staff may affect the availability of such equipment to the Company and may delay Meren’s exploration and development activities and result
in lower production.
INCREASED COSTS AND SUPPLY DISRUPTION
A failure to secure the services and equipment necessary for the Company’s operations for the expected price, on the expected timeline, or
at all, may have an adverse effect on the Company’s financial performance and cash flows. The Company’s operating and capital costs could
escalate and become uncompetitive due to supply chain disruptions, inflationary cost pressures, equipment limitations, escalating supply costs,
and additional government intervention through stimulus spending or additional regulations. The Company’s inability to manage costs may
impact project returns and future development decisions, which could have a material adverse effect on its financial performance and cash
flows. In addition, with rising inflation levels combined with global cost of living expenses, the Company may be faced with the challenge of how
to attract and retain employees. Though Meren does not directly control procurement decisions associated with all of our assets, the Company
works with its JV parties to ensure adequate contingency for cost inflation is incorporated into capital and operating budgets and that costs
are controlled within budget.
RISK FACTORS - CONTINUED
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Report to Shareholders | December 31, 2025
PAGE 34
SHARED OWNERSHIP AND DEPENDENCY ON JV PARTIES
The Company’s operations are primarily conducted together with one or more JV parties through contractual arrangements, including
unincorporated associations. In such instances, the Company may be dependent on, or affected by, the due performance and financial strength
of its JV parties. If a JV party fails to perform or becomes insolvent, the Company may, among other things, risk losing rights or revenues or
incur additional obligations or costs, experience delays, or be required to perform such obligations in place of its JV party. The Company and
its JV parties may also, from time to time, have different opinions on how to conduct certain operations or on what their respective rights and
obligations are under a certain agreement. If a dispute were to arise with one or more JV parties relating to a project, such dispute may have
material adverse effect on the Company’s or investee company’s operations relating to such project.
RISKS RELATING TO CONCESSIONS, LICENSES AND CONTRACTS
Meren’s operations are based on a relatively limited number of concession agreements, licenses and contracts. The rights and obligations under
such concessions, licenses and contracts may be subject to interpretation and could also be affected by, among other things, matters outside
the control of Meren. In case of a dispute, it cannot be certain that the view of the Company would prevail or that the Company otherwise
could effectively enforce its rights which, in turn, could have significantly negative effects on Meren. Also, if the Company or any of its JV
parties were found to have failed to comply with their obligations or liabilities under a concession, license or contract, including record-keeping,
budgeting, and time scheduling requirements, the Company’s or JV parties rights under such concession, license or contract may be terminated
or otherwise relinquished in whole or in part. The Company cannot guarantee that requirements are adequately met by its JV parties, which
could bring an increased risk of impairment and reduced future cash flow.
In May 2023, the Company submitted notices to withdraw from its concessions on Blocks 10BB, 13T and 10BA in Kenya. The Company’s
withdrawal from the concessions is subject to approvals from the Kenyan authorities and, while the Company is working with its JV parties and
the authorities to effect a smooth withdrawal process, there can be no certainty that such approvals will be forthcoming on terms acceptable
to all parties. Any delay or adverse outcome in the withdrawal process could result in additional costs, disputes or claims, and may adversely
affect the Company’s business, financial condition and results of operations.
GOVERNMENT REGULATIONS AND TAX RISK
The Company may be adversely affected by changes to applicable laws to which it is subject, and its host governments may implement new
applicable laws, modify existing ones, or interpret them in a manner that is detrimental to the Company. Such changes to the laws to which the
Company is subject could, amongst other things, result in a windfall tax, an increase in existing tax rates or the imposition of new ones or the
Company may be subject to tax assessments, all of which on their own or taken together could have a material adverse effect on the Company’s
business, financial condition, results of operations and prospects of the Company’s oil and gas assets.
As has become customary in Nigeria since 2019, the annual budget for Nigeria has been accompanied by a proposed finance bill that supports
the revenue needs indicated in the annual budget. This bill could include changes to tax laws, including laws that can affect directly or indirectly
the oil and gas industry.
Regulatory requirements affecting the oil and gas industry - including permitting rules, operational standards, local content requirements, and
ongoing amendments to sector-specific legislation - may materially affect the Company’s operations, timing of approvals, costs of compliance,
fiscal terms, and continued access to concessions. These regulatory developments are incorporated within the Company’s assessment of
Government Regulations and Tax Risk.
INTERNATIONAL OPERATIONS
Meren participates in oil and gas projects located in emerging markets, primarily in Africa. Oil and gas exploration, development and production
activities in these emerging markets are subject to significant political, economic, and other uncertainties that may adversely affect the
Company’s operations. The Company could be adversely affected by changes in applicable laws and policies in the countries where the Company
has interests. Additional uncertainties include, but are not limited to, the risk of war, terrorism, expropriation, civil unrest, nationalization,
renegotiation or nullification of existing or future concessions and contracts, the imposition of international sanctions, a change in crude oil or
gas pricing policies, changes to taxation laws and policies, assessments and audits (including income tax) against the Company by regulatory
authorities, difficulty or delays in obtaining necessary regulatory approvals, risks associated with potential future legal proceedings, and the
imposition of currency controls. These uncertainties, all of which are beyond the Company’s control, could have a material adverse effect on
the Company’s business, prospects and results of operations. In addition, if legal disputes arise related to oil and gas concessions acquired by
the Company, they could be subject to the jurisdiction of courts other than those of Canada. The Company’s recourse may be very limited in
the event of a breach by a government or government authority of an agreement governing a concession in which the Company acquires an
interest. The Company may require licenses or permits from various governmental authorities to carry out future exploration, development
and production activities. There can be no assurance that the Company will be able to obtain all necessary licenses and permits when required.
FOREIGN CURRENCY EXCHANGE RATE RISK
The Company is exposed to changes in foreign exchange rates as expenses in international subsidiaries, oil and gas expenditures, or financial
instruments may fluctuate due to changes in rates. The Company’s exposure is partially offset by sourcing capital projects and expenditures in
US dollars. The Company had no forward exchange contracts in place as at December 31, 2025.
DECOMMISSIONING
The Company is responsible for compliance with all applicable laws, regulations and contractual requirements regarding the decommissioning,
abandonment and reclamation of the Company’s assets at the end of their economic life.
RISK FACTORS - CONTINUED
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