FULLTEXT DEL 1 AV 2
Kvartalsrapport Q3 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 THIRD QUARTER 2025 RESULTS AND FOURTH
QUARTERLY DIVIDEND
Nov 13, 2025 (MER–TSX, MER–Nasdaq-Stockholm, MRNFF–OTCQX) – Meren Energy Inc. (“Meren”
or the “Company”) today published its financial and operating results for the three and nine months
ended September 30, 2025, and is pleased to declare its fourth quarterly distribution of approximately
$25 million under its base dividend policy.
Meren President and CEO, Roger Tucker commented: “The completion of the Prime amalgamation
marked a step-change for Meren and we have now honored our enhanced dividend policy with $100
million in 2025 distributions . We have also materially reduced our outstanding RBL debt amount to
underpin a stronger, more agile company that is built to deliver sustainable returns and withstand market
volatility.”
Highlights*
• Declared the fourth 2025 quarterly dividend of approximately $25.1 million, bringing total
distributions year-to-date to approximately $100.3 million.
• During Q3 2025:
o achieved average daily W.I. and entitlement production of 31,100 boepd and 35,600
boepd respectively, in line with expectation;
o sold three cargoes (approximately 3 MMbbl) at an average sales price of $70.8/bbl;
o reduced the RBL by $180.0 million, reducing interest expenses and ending Q3 2025
with a debt balance of $360.0 million;
o distributed the third quarterly cash dividend of approximately $25.1 million ($0.0371 per
share) in September 2025; and
o end of Q3 2025 cash balance of $176.7 million, resulting in a net debt position of $183.3
million with a Net Debt/ EBITDAX of 0.4x as at September 30, 2025. RBL facility
headroom of $192.3 million at the end of Q3 2025;
• During the first nine months of 2025:
o cashflow from operations before working capital adjustment of $243.1 million;
o EBITDAX of $368.0 million; and
o cash capital investments of $80.4 million.
• Post Q3 2025 reduced the RBL by a further $30.0 million taking the total RBL reduction year -
to-date to $420.0 million with a remaining outstanding debt balance of $330.0 million.
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2025 Third Quarter Results Highlights
Three months ended Nine months ended Years ended
Meren Highlights Unit September
30, 2025
September
30, 2024
September
30, 2025
September
30, 2024
December
31, 2024
Net income/ (loss) $’m 5.2 (289.2) 59.2 (285.3) (279.1)
Net income/ (loss)
per share – basic
$/
share 0.01 (2) (0.65) 0.10 (2) (0.63) (0.62)
Net debt position (3) $’m 183.3 193.2 183.3 193.2 289.1
WI production (3) boepd 31,100 35,800 31,800 33,800 34,000
Entitlement
production (3) boepd 35,600 41,200 36,300 38,800 38,800
Cash flow from
operations (4, 5) $’m 65.6 n/a 243.1 n/a n/a
EBITDAX (4) $’m 119.8 n/a 368.0 n/a n/a
Capital
investments(4) $’m 21.8 n/a 80.4 n/a n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on pages 13-16 of the
Report to Shareholders for the period ended September 30, 2025.
(2) Based on the weighted average number of shares outstanding for the three and nine months ended September 30, 2025, of 675,512 ,565 and
607,202,542 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 and nine months period ended September 30, 2025.
(4) Highlights are reported for the year 2025 only, on a constructed financial information basis, see pages 10-11 for further information.
(5) Cash flow from operations before working capital and interest payments.
Outlook
Shareholder Returns
The Company is pleased to announce that its Board has declared the distribution of the Company’s
fourth quarterly cash dividend in 2025 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 November 21, 2025.
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 December 9, 2025;
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 on December
12, 2025.
To execute the payment of the dividend, a temporary administrative cross border transfer closure will
be applied by Euroclear from November 19, 2025, up to and including November 21, 2025, 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 Company’s Board views the base annual distribution policy to be prudent with due consideration
for its capital allocation options and the priority of maintaining a strong balance sheet in a range of
market scenarios. Future dividend declarations are subject to customary Board approval and consents.
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Nigeria
In partnership with its JV partners, the Company is focused on enhancing production performance
across its three producing fields, Akpo, Egina and Agbami.
Following the break to the Akpo/Egina (PPL 2/3) drilling campaign in Q3 2025, efforts are underway to
recommence the campaign. As previously communicated, this break will allow for the interpretation of
4D seismic data to enhance the maturation of future i nfill well opportunities. Accordingly, the aim is to
secure a deepwater drilling rig within the gap and start with the drilling of the Akpo Far East near -field
prospect, followed by the drilling of further development wells on Akpo and Egina fields.
Akpo Far East is an infrastructure -led exploration opportunity that in case of commercial exploration
success, presents an attractive short cycle, high return investment opportunity that would utilise the
existing Akpo facilities. Akpo Far East prospect has an unrisked, best estimate, gross field prospective
resource volume of 143.6 MMboe. The targeted hydrocarbons are predicted to be light, high gas -oil
ratio (“GOR”) oil equivalent to those found in the Akpo field. If successful, initial production could b e
achieved from existing production manifolds with the potential to add significant reserves.
The JV partners are continuing the project optimization work for the Preowei field with the aim of
completing the studies to provide the necessary results to move the project further along towards FID.
A Q3 workshop, during which the operator presented fin dings from the ongoing re -assessment of the
Preowei seismic data, indicated an increase in recoverable resources and delivered encouraging
results. This optimization exercise will continue through early 2026 with additional work to validate these
resources and optimize the project.
For the Agbami field, in addition to the ongoing 2024 4D seismic interpretation, rig and long lead items
contracting activities are progressing for the 2027 infill drilling campaign. Separately, the Ikija appraisal
well is being matured to enable its inclusion as part of the upcoming Agbami Infill drilling campaign.
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 exp loration costs on Blocks 2912 and 2913B
remains fully funded through to first commercial production, without any financial cap.
During the third quarter, the joint-venture partners continued to progress the Environmental and Social
Impact Assessment (ESIA) and associated stakeholder -engagement program, marking an important
milestone toward regulatory approvals. Front-End Engineering Design (“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:
o FEED and ESIA completion by the end of 2025;
o Final Investment Decision (“FID”): Targeted for 2026;
o First Oil: 2030.
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 2192 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 Walvis Bay and Lüderitz.
Execution and infrastructure challenges, including m arine services capacity, environmental approvals,
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and gas monetization, present both risks and opportunities as the country positions itself to attract
capital and expand its deepwater supply chain.
Meren’s indirect exposure to Venus represents a material long -term growth opportunity within a fully
carried structure, offering potential for future cash -flow generation with no near -term funding
commitments.
South Africa Orange Basin, Block 3B/4B
Following the granting of an Environmental Authorization for exploration activities (drilling of up to 5
exploration wells) by the Department of Mineral Resources and Energy for the Republic of South Africa
on September 16, 2024, the legislative notification and appeals process is currently 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 Authorisation is
confirmed and has identified Nayla, a prospect that lies in the north of the license area as the potential
drilling target.
The Company completed a strategic farm down agreement with TotalEnergies and QatarEnergy during
Q3 2024 that provide it with exploration carry. Transaction highlights are:
• Maximum transaction value of up to $46.8 million to the Company.
• The Company will receive, subject to achieving certain milestones defined in the farm down
agreement, staged payments for a total cash amount of $10.0 million, of which $3.3 million was
received at completion with the remaining balance to be received in tw o successive payments
conditional upon achieving key operational and regulatory milestones.
• The Company will also receive a full carry of its retained share of all JV costs, up to a cap, that
is repayable to TotalEnergies and QatarEnergy from production, and which is expected to be
adequate to fund the Company’s share of drilling for 1-2 wells on the license.
Equatorial Guinea, EG-18 and EG-31
Following the active data room exercise, the next phase of activity will focus on progressing potential
partnership discussions, beginning with the evaluation of potential farm-in offers, and engaging with the
government to define the forward plan for both blocks.
If the Company is successful in attracting farm -in partner(s) for these blocks, subject to customary
consents and approvals including governmental and regulatory permissions, the Company anticipates
that newly formed JVs could plan for exploration drilling in late 2026 or 2027. However, there is no
guarantee that the Company can secure farm-in partners on acceptable terms.
2025 Management Guidance and Actuals
The revised 2025 Management Guidance as included in the Q 2 2025 MD&A is unchanged and a
summary is presented below for completeness.
Original 2025
Guidance
Revised 2025
Guidance
First nine months of 2025
actuals
WI production (kboepd) (1) 28.0 – 33.0 30.0 – 33.0 31.8
Entitlement production
(kboepd) (2) 32.0 – 37.0 34.5 – 37.5 36.3
EBITDAX ($ million) (3) 500 - 600 450 - 500 368.0
Cash flow from operations ($
million) (3) 320 - 370 260 - 310 243.1
Capital investments ($
million) 150 - 190 100 - 140 80.4
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(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 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
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 b etter 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.
Management Conference Call
Senior management will hold a conference call to discuss the results on Monday, November 17, 2025,
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-third-quarter-results-nov-2025.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 operated by Majors. The Company holds a l eading 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 Nov 13, 2025.
Advisory Regarding Oil and Gas Information
The terms boe (barrel of oil equivalent) is used throughout this press release. Such terms may be
misleading, particularly if used in isolation. Production data are based on a conversion ratio of six
thousand cubic feet per barrel (6 Mcf: 1bbl). This conversion ratio i s 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 significa ntly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis
may be misleading as an indication of value. Petroleum references in this press release are to light and
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medium gravity crude oil and conventional natural gas in accordance with NI 51 -101 and the COGE
Handbook.
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 enlarged
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 partners
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.
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 regarding capital priorities . Forward-looking statements are based on a number of
assumptions, including but not limited to, the a bility 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, availabilit y 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 f ailure 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.
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Report to
Shareholders
For the Period Ended September 30, 2025
Q3
25
Meren Energy Inc. (previously called Africa Oil Corp.)
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Report to Shareholders | September 30, 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
Agreement”
means the definitive agreement between the Company, BTG Oil & Gas and BTG Holding the entity which
holds the interests of BTG Oil & Gas in Meren Coop, to reorganize and consolidate their respective 50:50
shareholdings in Meren Coop.
“Applicable law” means all laws and regulations issued by authorities that have appropriate jurisdiction over the Company.
“Azinam” means Azinam Ltd.
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”, “PSC”
or “Production Sharing
Contract”
means concessions, production sharing contracts 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.
“DST” means Drill Stem Testing.
E
“EPS” means Early Production System.
“EBITDAX” means Earnings Before Interest, Taxes, Depreciation & Impairment, Amortization and Exploration
Expenses.
“Eco”
means Eco (Atlantic) Oil & Gas Ltd, an international oil and gas exploration company that holds working
interests in four exploration Blocks offshore Namibia and operates one exploration Block offshore South
Africa and is party with the Company in Block 3B/4B, offshore South Africa and holds working interest in
two exploration Blocks offshore Guyana.
“Entitlement
production”
means production that is calculated using the economic interest methodology and includes cost oil, profit
oil, tax oil and royalty oil.
“ESG” means Environmental, Social and Governance.
“ESHS” means Environmental, Social, Health and Safety.
“ESIA” means Environmental and Social Impact Assessment.
F
“FCF” means Free Cash Flow.
“FEED” means Front End Engineering and Design.
“FID” means Final Investment Decision.
“FPSO” means Floating Production Storage and Offloading.
G “GHG” means Greenhouse Gas.
H “H1” means first six months of the reporting period.
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.
GLOSSARY
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Report to Shareholders | September 30, 2025
PAGE 3
L
“LTI” means lost time injury.
“LTIP” means Long Term Incentive Plan.
M
“Mcf” means million cubic feet.
“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 Nigeria 52
Limited” means Meren Nigeria 52 Limited (previously named Prime 127 Nigeria Limited).
“Meren Nigeria 234
Limited” 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 261” means the Petroleum Prospecting License containing the South Egina prospect.
“PPT” means Profit Petroleum Tax.
“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 “spud” or “spudded” means the initial drilling for an oil well.
T
“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.
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Report to Shareholders | September 30, 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 three and nine
months ended September 30, 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 unaudited interim condensed consolidated financial statements for the three and nine months ended
September 30, 2025, and 2024, and also should be read in conjunction with the audited consolidated financial statements for the years ended
December 31, 2024, and 2023, and related notes thereto.
The financial information in this MD&A is derived from the Company’s unaudited interim condensed 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”), including International Accounting Standard (“IAS”) 34 Interim Financial Reporting.
This MD&A was reviewed and approved by the Board of Directors. The effective date of this MD&A is November 13, 2025.
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 now also trade on the OTCQX Best Market (“OTCQX”) in the U.S. under the ticker ‘MRNFF’.
Meren’s long-term objective is to implement a steady and predictable total shareholder returns model underpinned by an enhanced base dividend
policy, whilst delivering organic growth from its core assets and pursuing disciplined inorganic growth opportunities focused on producing
assets. 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 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 prospectivity.
===== SIDA 11 =====
Report to Shareholders | September 30, 2025
PAGE 5
HIGHLIGHTS AND OUTLOOK
THE FIRST NINE MONTHS OF 2025 AND POST PERIOD HIGHLIGHTS
● Declared the fourth 2025 quarterly dividend of approximately $25.1 million, bringing total distributions year-to-date to approximately
$100.3 million.
● During Q3 2025:
» Achieved average daily W.I. and entitlement production of 31,100 boepd and 35,600 boepd respectively, in line with expectation;
» Sold three cargoes (approximately 3 MMbbl) at an average sales price of $70.8/bbl;
» Reduced the RBL by $180.0 million, reducing interest expenses and ending Q3 2025 with a debt balance of $360.0 million;
» Distributed the third quarterly cash dividend of approximately $25.1 million ($0.0371 per share) in September 2025; and
» End of Q3 2025 cash balance of $176.7 million, resulting in a net debt position of $183.3 million with a Net Debt/ EBITDAX of 0.4x as at
September 30, 2025. RBL facility headroom of $192.3 million at the end of Q3 2025;
● During the first nine months of 2025:
» Cashflow from operations before working capital adjustment of $243.1 million;
» EBITDAX of $368.0 million; and
» Cash capital investments of $80.4 million.
● Post Q3 2025 reduced the RBL by a further $30.0 million taking the total RBL reduction year-to-date to $420.0 million with a remaining
outstanding debt balance of $330.0 million.
FINANCIAL SUMMARY (1)
Three months ended Nine months ended Year ended
Unit
September
30, 2025
September
30, 2024
September
30, 2025
September
30, 2024
December 31,
2024
Meren highlights
Net income/ (loss) $’m 5.2 (289.2) 59.2 (285.3) (279.1)
Net income/ (loss) per share – basic (2) $/ share 0.01 (0.65) 0.10 (0.63) (0.62)
Net debt position (3) $’m 183.3 193.2 183.3 193.2 289.1
WI production (3) boepd 31,100 35,800 31,800 33,800 34,000
Entitlement production (3) boepd 35,600 41,200 36,300 38,800 38,800
Cash flow from operations (4, 5) $’m 65.6 n/a 243.1 n/a n/a
EBITDAX (4) $’m 119.8 n/a 368.0 n/a n/a
Capital investments (4) $’m 21.8 n/a 80.4 n/a n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on Pages 13-16.
(2) Based on the weighted average number of shares outstanding for the three and nine months ended September 30, 2025, of 675,512,565 and
607,202,542 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 and nine months period ended September 30, 2025.
(4) Highlights are reported for the year 2025 only, on a constructed financial information basis, see Pages 10-11 for further information.
(5) Cash flow from operations before working capital and interest payments.
===== SIDA 12 =====
Report to Shareholders | September 30, 2025
PAGE 6
HIGHLIGHTS AND OUTLOOK - CONTINUED
OUTLOOK
Shareholder Returns
The Company is pleased to announce that its Board has declared the distribution of the Company’s fourth quarterly cash dividend in 2025 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 November
21, 2025.
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 December 9, 2025; 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 on December 12, 2025.
To execute the payment of the dividend, a temporary administrative cross border transfer closure will be applied by Euroclear from November
19, 2025, up to and including November 21, 2025, 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 Company’s Board views the base annual distribution policy to be prudent with due consideration for its capital allocation options and the
priority of maintaining a strong balance sheet in a range of market scenarios. Future dividend declarations are subject to customary Board
approval and consents.
Nigeria
In partnership with its JV partners, the Company is focused on enhancing production performance across its three producing fields, Akpo, Egina
and Agbami.
Following the break to the Akpo/Egina (PPL 2/3) drilling campaign in Q3 2025, efforts are underway to recommence the campaign. As previously
communicated, this break will allow for the interpretation of 4D seismic data to enhance the maturation of future infill well opportunities.
Accordingly, the aim is to secure a deepwater drilling rig within the gap and start with the drilling of the Akpo Far East near-field prospect,
followed by the drilling of further development wells on Akpo and Egina fields.
Akpo Far East is an infrastructure-led exploration opportunity that in case of commercial exploration success, presents an attractive short cycle,
high return investment opportunity that would utilise the existing Akpo facilities. Akpo Far East prospect has an unrisked, best estimate, gross
field prospective resource volume of 143.6 MMboe. The targeted hydrocarbons are predicted to be light, high gas-oil ratio (“GOR”) oil equivalent
to those found in the Akpo field. If successful, initial production could be achieved from existing production manifolds with the potential to add
significant reserves.
The JV partners are continuing the project optimization work for the Preowei field with the aim of completing the studies to provide the
necessary results to move the project further along towards FID. A Q3 workshop, during which the operator presented findings from the
ongoing re-assessment of the Preowei seismic data, indicated an increase in recoverable resources and delivered encouraging results. This
optimization exercise will continue through early 2026 with additional work to validate these resources and optimize the project.
For the Agbami field, in addition to the ongoing 2024 4D seismic interpretation, rig and long lead items contracting activities are progressing
for the 2027 infill drilling campaign. Separately, the Ikija appraisal well is being matured to enable its inclusion as part of the upcoming Agbami
Infill drilling campaign.
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%),
NAMCOR (10%) 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.
During the third quarter, the joint-venture partners continued to progress the Environmental and Social Impact Assessment (ESIA) and associated
stakeholder-engagement program, marking an important milestone toward regulatory approvals. Front-End Engineering Design (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:
● FEED and ESIA completion by the end of 2025;
● Final Investment Decision (“FID”): Targeted for 2026;
● First Oil: 2030.
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 2192 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 Walvis Bay and Lüderitz. 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.
Meren’s indirect exposure to Venus represents a material long-term growth opportunity within a fully carried structure, offering potential for
future cash-flow generation with no near-term funding commitments.
===== SIDA 13 =====
Report to Shareholders | September 30, 2025
PAGE 7
HIGHLIGHTS AND OUTLOOK - CONTINUED
South Africa Orange Basin, Block 3B/4B
Following the granting of an Environmental Authorization for exploration activities (drilling of up to 5 exploration wells) by the Department
of Mineral Resources and Energy for the Republic of South Africa on September 16, 2024, the legislative notification and appeals process is
currently 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.
The Company completed a strategic farm down agreement with TotalEnergies and QatarEnergy during Q3 2024 that provide it with exploration
carry. Transaction highlights are:
● Maximum transaction value of up to $46.8 million to the Company.
● The Company will receive, subject to achieving certain milestones defined in the farm down agreement, staged payments for a total cash
amount of $10.0 million, of which $3.3 million was received at completion with the remaining balance to be received in two successive
payments conditional upon achieving key operational and regulatory milestones.
● The Company will also receive a full carry of its retained share of all JV costs, up to a cap, that is repayable to TotalEnergies and QatarEnergy
from production, and which is expected to be adequate to fund the Company’s share of drilling for 1-2 wells on the license.
Equatorial Guinea, Blocks EG-18 and EG-31
Following the active data room exercise, the next phase of activity will focus on progressing potential partnership discussions, beginning with
the evaluation of potential farm-in offers, and engaging with the government to define the forward plan for both blocks.
If the Company is successful in attracting farm-in partner(s) for these blocks, subject to customary consents and approvals including
governmental and regulatory permissions, the Company anticipates that newly formed JVs could plan for exploration drilling in late 2026 or
2027. However, there is no guarantee that the Company can secure farm-in partners on acceptable terms.
2025 MANAGEMENT GUIDANCE AND ACTUALS
The revised 2025 Management Guidance as included in the Q2 2025 MD&A is unchanged and a summary is presented below for completeness.
Original 2025 Guidance Revised 2025 guidance
First nine months of
2025 actuals
WI production (kboepd) (1) 28.0 – 33.0 30.0 – 33.0 31.8
Entitlement production (kboepd) (2) 32.0 – 37.0 34.5 – 37.5 36.3
EBITDAX ($ million) (3) 500 - 600 450 – 500 368.0
Cash flow from operations ($ million) (3) 320 - 370 260 - 310 243.1
Capital investments ($ million) 150 - 190 100 - 140 80.4
(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 14 =====
Report to Shareholders | September 30, 2025
PAGE 8
THE COMPANY’S SHAREHOLDING AND
WORKING INTERESTS
The Company’s material interests and material exploration partnership interests as at September 30, 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 Corporation
Famfa Oil
8%
32%
60% (carried)
PML 2, 3, 4 and
PPL 261 – PSA (3) May 24, 2043
Meren
TotalEnergies
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
EG-31 March 1, 2026
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.
Information on the Company’s equity interests in Africa Energy and Impact is included in ‘Equity Investments in Associates’ on Page 18.
===== SIDA 15 =====
Report to Shareholders | September 30, 2025
PAGE 9
BUSINESS UPDATE
SHAREHOLDER RETURNS
Pursuant to the Company’s current Normal Course Issuer Bid (“NCIB”) share repurchase program that was launched on December 6, 2024,
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 18,362,364 Common Shares of the Company, which represented 5% of its “public float” of 367,247,289
Common Shares as at November 22, 2024.
Purchases of Common Shares may occur over a period of up to twelve months commencing December 6, 2024, and ending on the earlier of
December 5, 2025, 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.
As detailed in the Highlights and Outlook section, the Company has declared the distribution of the Company’s fourth quarterly cash dividend in
2025 of approximately $25.1 million or $0.0371 per share.
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 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 Nine months ended Years ended
Unit
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
December 31,
2024
Total gross field production boepd 250,100 285,400 253,500 274,700 273,600
Average daily WI production (1) boepd 31,100 35,800 31,800 33,800 34,000
Average daily entitlement production boepd 35,600 41,200 36,300 38,800 38,800
Oil volumes sold MMbbl 3.0 4.0 9.0 9.0 9.0
Gas volumes sold bcf 4.6 4.6 14.6 12.4 17.4
Oil/gas percentage split (2) % 71%/29% 83%/17% 72%/28% 83%/17% 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.
The total gross field production in Q3 2025 decreased compared to Q3 2024, primarily due to the expected natural reservoir decline across
all assets in addition to the events described below. Production was proactively managed during operational challenges, ensuring steady
performance across fields.
Production from the Akpo and Egina fields was periodically affected by gas export restrictions at the Nigeria LNG facility. These gas export
restrictions were caused by a planned maintenance shutdown mid-quarter, as well as isolated unplanned events including liquid handling issues.
Given the aging nature of the NLNG facility, efforts are underway to enhance operational reliability and reduce the risk of unplanned events.
At the Agbami field, production was temporarily adjusted to manage flare and sand production, while facilitating scheduled maintenance to
support stable output in future periods. This included a brief shutdown of the seawater injection systems to complete essential maintenance
and repairs, ensuring operational uptime.
The impact of these operational challenges was mitigated by several factors. Despite a pause in the drilling campaign this year, the new Egina
wells brought on stream in Q2 2025 continued to perform in line with expectations. Furthermore, the Akpo well brought online in Q3 2025
following the successful well intervention in July also reduced the additional production downturn. The foregoing, combined with the strong
performance from Akpo wells and the restart of water injection in the Agbami field, helped to offset the disruptions described above.
In Q3 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 $70.8/bbl. In Q3 2024, four oil liftings were allocated with total sales volume of approximately 4.0 million barrels at an average realized oil
price of $80.8/bbl.
In the first nine months of 2025, 9 oil liftings were allocated with a total sales volume of approximately 9.0 million barrels of oil at an average
realized oil price of $74.9/bbl, compared to Dated Brent average of $70.9/bbl. In the first nine months of 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.
===== SIDA 16 =====
Report to Shareholders | September 30, 2025
PAGE 10
BUSINESS UPDATE - CONTINUED
FINANCIAL
Total revenues, cost of sales, gross profit, opex/boe, tax and net debt numbers included in the narrative discussion below 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 interim condensed
consolidated statement of net income/(loss) and comprehensive income/(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 to explain performance is included in the following tables to present on a consolidated basis, net income for
the first nine months of 2025 and cash flow statement for the first nine months of 2025, whereby the Meren interim condensed consolidated
statement of net income/(loss) and comprehensive income/(loss) and the Meren interim condensed consolidated statement of cash flows
for the first nine months of 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 in the constructed financial information are included 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.
Constructed financial information for purposes of explaining performance
Interim condensed consolidated statement of net income
(Expressed in millions of United States Dollars)
For the nine months ended
Meren first nine
months of 2025
per Financial
Statements
Meren Coop
for period from
January 1, 2025, to
March 19, 2025 Adjustments (1)
September 30,
2025
Revenue 362.4 323.5 - 685.9
Cost of Sales
Production costs (93.2) (187.4) 2.0 (278.6)
Depletion costs (155.0) (71.3) - (226.3)
(248.2) (258.7) 2.0 (504.9)
Gross profit 114.2 64.8 2.0 181.0
General and administrative expenses (31.4) (6.2) - (37.6)
Operating (loss)/ profit 82.8 58.6 2.0 143.4
Finance income 3.6 2.4 - 6.0
Finance expense (35.3) (21.3) - (56.6)
Net financial items (31.7) (18.9) - (50.6)
Share of profit from investment in joint venture 2.9 - (2.9) -
Share of loss from investments in associates (2.4) - - (2.4)
Reversal of impairment of investment in joint venture 55.9 - (55.9) -
Profit before tax 107.5 39.7 (56.8) 90.4
Income tax (48.3) (34.0) - (82.3)
Net income attributable to common shareholders 59.2 5.7 (56.8) 8.1
(1) Adjustments to remove items related to Meren Coop as fully consolidated above.
===== SIDA 17 =====
Report to Shareholders | September 30, 2025
PAGE 11
BUSINESS UPDATE - CONTINUED
Interim condensed consolidated statement of cash flows
(Expressed in millions of United States Dollars)
For the nine months ended
Meren first nine
months of 2025
per Financial
Statements
Meren Coop
for period from
January 1, 2025, to
March 19, 2025 Adjustments (1)
September 30,
2025
Cash flows generated by/ (used in):
Operations
Profit before tax 107.5 39.7 (56.8) 90.4
Adjustments as per financial statements 52.4 41.5 58.8 152.7
Net cash generated in operating activities before working
capital 159.9 81.2 2.0 243.1
Changes in working capital 33.6 (8.2) - 25.4
Net cash generated in operating activities 193.5 73.0 2.0 268.5
Investing
Investments in oil and gas properties and intangible
exploration assets (55.8) (22.6) (2.0) (80.4)
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 3.6 2.2 - 5.8
Cash acquired from Meren Coop consolidation (2) 380.4 - (381.3) (0.9)
Net cash generated/ (used) in investing activities 423.9 (20.4) (443.3) (39.8)
Financing
Repayment RBL Facility (390.0) - - (390.0)
Repayment of principal portion of lease commitments (0.5) - - (0.5)
Dividends paid to shareholders (75.2) (120.0) 120.0 (75.2)
Repurchase of share capital (8.3) - - (8.3)
Interest expense paid (28.1) (10.8) - (38.9)
Net cash (used)/ generated in financing activities (502.1) (130.8) 120.0 (512.9)
Foreign exchange variation on cash and cash equivalents
Total cash flow 115.3 (78.2) (321.3) (284.2)
Cash and cash equivalents, beginning of the period 61.4 399.5 - 460.9
Cash and cash equivalents, end of the period 176.7 321.3 (321.3) 176.7
(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 18 =====
Report to Shareholders | September 30, 2025
PAGE 12
BUSINESS UPDATE - CONTINUED
Financial Metrics (1)
Three months ended Nine months ended Years ended
Unit
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
December 31,
2024
Total revenues $’m 216.7 333.0 685.9 778.3 782.7
Cost of Sales (2) $’m 161.0 238.4 504.9 495.6 428.2
Gross profit $’m 55.7 94.6 181.0 282.7 354.5
Opex/boe (3,4) $/boe 10.7 9.8 11.8 10.4 10.3
Cash flow from operations before
working capital $’m 65.6 n/a 243.1 n/a n/a
Cash flow from operations $’m 146.7 n/a 268.5 n/a n/a
Free cash flow $’m 126.0 n/a 228.7 n/a n/a
Free cash flow/boe (4) $/boe 38.2 n/a 23.1 n/a n/a
Tax $’m 27.1 23.2 82.3 76.3 120.5
Capex $’m 21.8 n/a 80.4 n/a n/a
Net Debt $’m 183.3 193.2 183.3 193.2 289.1
EBITDAX $’m 119.8 n/a 368.0 n/a n/a
Net Debt/EBITDAX (5) ratio 0.4 n/a 0.4 n/a n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on Pages 13-16.
(2) 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.
(3) Opex represents direct production costs.
(4) Boe is calculated on an entitlement basis.
(5) Calculated based on extrapolating the first nine months of 2025 EBITDAX to a full year EBITDAX number.
Total revenues
Three months ended Nine months ended Years ended
Unit
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
December 31,
2024
Oil revenue $’m 212.2 327.2 671.1 762.2 762.2
Gas revenue $’m 4.5 5.8 14.8 16.1 20.5
Total revenue $’m 216.7 333.0 685.9 778.3 782.7
Realized oil prices (1) $/bbl 70.8 80.8 74.9 84.6 84.6
Oil volumes sold MMbbl 3.0 4.0 9.0 9.0 9.0
Realized gas prices $’m/bcf 1.0 1.3 1.0 1.3 1.2
Gas volumes sold Bcf 4.6 4.6 14.6 12.4 17.4
(1) Realized oil prices might be different to values calculated from the table above due to rounding.
===== SIDA 19 =====
Report to Shareholders | September 30, 2025
PAGE 13
BUSINESS UPDATE - CONTINUED
The decrease in oil revenue in Q3 2025 was mainly driven by lower lifting volumes compared to Q3 2024 and a lower realized price of $70.8/
bbl in Q3 2025 compared to $80.8/bbl in Q3 2024.
The decrease in oil revenue in the first nine months of 2025 was mainly driven by a lower realized oil price of $74.9/bbl in the first nine months
of 2025 compared to $84.6/bbl in the first nine months of 2024.
Cost of sales
Three months ended Nine months ended Years ended
$’m
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
December 31,
2024
Depletion costs 73.0 94.0 226.3 285.0 372.0
Cost of operations 35.3 37.4 117.0 110.4 146.1
Movements on overlift/ underlift balances 37.3 86.0 116.0 33.6 (171.2)
Royalties – oil and gas 10.6 18.0 33.8 56.2 70.2
Others 4.8 3.0 11.8 10.4 11.1
Total cost of sales 161.0 238.4 504.9 495.6 428.2
Cost of sales decreased in Q3 2025 compared to Q3 2024. The decrease in costs of sales is mainly driven by a lower overlift movement in Q3
2025 compared to Q3 2024, lower depletion costs and lower royalties as a result of lower oil prices.
Cost of sales slightly increased in the first nine months of 2025 compared to the first nine months of 2024. There was a larger overlift
movement in the first nine months of 2025 compared to the first nine months of 2024, this was offset against lower depletion costs and lower
royalties as a result of lower oil prices.
Other costs of sales mainly relates to the NDDC Levy, which concerns the Niger Delta Development Commission Levy imposed to fund the
sustainable development of the Niger Delta region and to the HCDF Levy, which concerns the Nigerian Content Development Fund.
Opex/boe
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 Nine months ended Years ended
Unit
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
December 31,
2024
Cost of operations $’m 35.3 37.4 117.0 110.4 146.1
Entitlement production MMboe 3.3 3.8 9.9 10.6 14.2
Opex/boe $/boe 10.7 9.8 11.8 10.4 10.3
Opex/boe increased in Q3 2025 compared to Q3 2024 primarily from lower entitlement production and the first nine months of 2025
compared to the first nine months of 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.
===== SIDA 20 =====
Report to Shareholders | September 30, 2025
PAGE 14
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 Nine months ended Years ended
$’m
September 30,
2025 (1)
September 30,
2024 (1)
September 30,
2025 (1)
September 30,
2024 (1)
December 31,
2024 (1)
Cash flow from operations 146.7 n/a 268.5 n/a n/a
Working capital adjustments included in cash flow from
operations (81.1) n/a (25.4) n/a n/a
Cash flow from operations before working capital 65.6 n/a 243.1 n/a 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 Nine months ended Years ended
Unit
September 30,
2025 (1)
September 30,
2024 (1)
September 30,
2025 (1)
September 30,
2024 (1)
December 31,
2024 (1)
Total cash flow $’m (89.9) n/a (284.2) n/a n/a
Add back dividends paid to shareholders $’m 25.1 n/a 75.2 n/a n/a
Add back repurchase of share capital $’m - n/a 8.3 n/a n/a
Add back debt service costs (2) $’m 190.8 n/a 429.4 n/a n/a
Free cash flow $’m 126.0 n/a 228.7 n/a n/a
Entitlement production MMboe 3.3 n/a 9.9 n/a n/a
Free cash flow/boe $/boe 38.2 n/a 23.1 n/a 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 21 =====
Report to Shareholders | September 30, 2025
PAGE 15
BUSINESS UPDATE - CONTINUED
Tax
The tax expense is made up of the following items:
Three months ended Nine months ended Years ended
$’m
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
December 31,
2024
Deferred income tax (29.0) (27.0) (45.9) (56.4) (80.9)
Education tax 4.7 5.1 10.5 12.1 14.2
Corporate income tax 44.9 45.1 93.2 113.0 130.1
Withholding tax on dividends 6.5 - 24.5 7.5 22.5
Capital gains tax - - - - 33.0
Petroleum Profit Tax - - - (2.3) (2.3)
Other taxes - - - 2.4 3.9
Total tax 27.1 23.2 82.3 76.3 120.5
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.
Capital expenditure
Capital expenditure is made up of the following items:
Three months ended Nine months ended Years ended
$’m
September 30,
2025 (1)
September 30,
2024 (1)
September 30,
2025 (1)
September 30,
2024 (1)
December 31,
2024 (1)
Nigeria 20.6 n/a 76.5 n/a n/a
Equatorial Guinea 1.2 n/a 3.8 n/a n/a
South Africa - n/a 0.1 n/a n/a
Total capex 21.8 n/a 80.4 n/a n/a
(1) Capital expenditure has been reported for the year 2025 only on a constructed financial information basis.
Capital expenditure in Q3 2025 and the first nine months of 2025 in Nigeria mainly related to 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.
Nine months ended Years ended
As at/ $’m
September 30,
2025
September 30,
2024
December 31,
2024
Loans and borrowings 360.0 750.0 750.0
Cash and cash equivalents (176.7) (556.8) (460.9)
Net Debt 183.3 193.2 289.1
As at September 30, 2025, the Company has $176.7 million of cash and cash equivalents and $360.0 million of debt (as at December 31, 2024
- $460.9 million of cash and cash equivalents and $750.0 million of debt). During the first nine months of 2025, the Company repaid $390.0
million under its RBL facility reducing outstanding debt to $360.0 million. RBL facility headroom of $192.3 million at the end of Q3 2025.
===== SIDA 22 =====
Report to Shareholders | September 30, 2025
PAGE 16
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 and impairment expenses. 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 the leverage.
Three months ended Nine months ended Twelve months ended
$’m
September
30, 2025 (1)
September
30, 2024 (1)
September
30, 2025 (1)
September
30, 2024 (1)
September
30, 2025 (1)
December 31,
2024 (1)
Total profit/ (loss) 5.2 n/a 8.1 n/a n/a n/a
Add back:
Tax 27.1 n/a 82.3 n/a n/a n/a
Finance costs 15.0 n/a 56.6 n/a n/a n/a
Finance income (1.2) n/a (6.0) n/a n/a n/a
Depletion, depreciation and amortization
costs 73.7 n/a 227.0 n/a n/a n/a
EBITDAX 119.8 n/a 368.0 n/a n/a n/a
Net Debt 183.3 183.3
Net Debt/EBITDAX (2) 0.4 0.4
(1) EBITDAX and Net Debt/EBITDAX have been reported for the year 2025 only on a constructed financial information basis.
(2) Net debt/EBITDAX has been calculated based on extrapolating the first nine months of 2025 EBITDAX to a full year EBITDAX number.
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.
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.
In most of the Group’s oil offtake contracts, the Dated Brent component of the forward price at the time of entering the contract is not fixed
but determined on or around the date of the lifting for spot cargos either on an average monthly basis, 5-days after bill of lading date or similar
pricing mechanism. If the Group wants to utilize the oil offtake contract for commodity risk management, it can either fix the Dated Brent
component or utilize a trigger pricing mechanism. For the trigger pricing mechanism, when the forward price curve falls below a certain trigger
price for a certain month, this mechanism provides an irrevocable instruction to an off-taker to fix the Dated Brent price component of a cargo.
The average cargo size lifted is one million barrels of oil.
Oil sales were comprised of the following:
Three months ended Nine months ended Year ended
Oil Sales Unit
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
December 31,
2024
Number of cargo liftings 3 4 9 9 9
Of which:
Sold forward with a fixed Dated Brent 1 2 4 2 2
Sold at spot 2 2 5 7 7
3 4 9 9 9
Gross crude oil sales
Quantity in Mboe Mboe 3,000.5 4,047.6 8,963.2 9,012.8 9,012.8
Average sales price $/bbl 70.8 80.8 74.9 84.6 84.6
Average Bloomberg Dated Brent for the
period $/bbl 69.1 80.3 70.9 82.7 82.7
===== SIDA 23 =====
Report to Shareholders | September 30, 2025
PAGE 17
BUSINESS UPDATE - CONTINUED
The Company sold 3 cargoes during Q3 2025 at a price of $70.8/bbl. Of the 3 cargoes expected for the remainder of the year post Q3 2025, 2
cargos have the trigger price mechanism activated at an average price of $64.6/bbl. The remaining cargo is currently unhedged with no trigger
price mechanism in place.
The combination of achieved sales prices in the first nine months of 2025 and future fixed prices have materially de-risked the impact of oil
price volatility on the business for 2025.
Of the cargoes expected for the year ended December 31, 2026, 2 cargoes have the trigger price mechanism activated at an average price of
$62.1/bbl.
In October 2025, the Company entered into a monthly settled swap arrangement at a strike price of $63.58/bbl for 0.6 MMboe for the three
months ended September 30, 2026. This means that if the daily average Dated Brent close price in each calculation period falls below the strike
price, then the Company is compensated in cash for the difference. If the daily average Dated Brent close price in the period is above the strike
price, then the Company will pay the difference.
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 19-20 of the Company’s Annual Information Form (“AIF”) for the Year Ended December 31, 2024, for the detailed
commercial information, and pages 41–50 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.
During Q3 2025, activities across the Nigerian asset base continued to focus on optimising production performance across the three producing
fields, while also progressing efforts to mature the remaining non-producing assets towards an investment decision.
In Q3 2025, there was a break in the Akpo/Egina drilling campaign with a plan to restart in 2026. This break will allow for the interpretation
of the 4D seismic data and detailed results from the wells drilled to enhance the maturation of future infill wells and other opportunities.
Accordingly, the plan is to also prioritize the drilling of the Akpo Far East near-field prospect, followed by the drilling of further development
wells on Akpo and Egina fields. Efforts are underway to secure a rig for this campaign.
For the Agbami field, in addition to the ongoing 2024 4D seismic interpretation, rig and long lead items contracting activities are progressing
for the 2027 infill drilling campaign. The current plan is for the drilling rig to be mobilized to the Agbami area by Q4 2026 to drill a couple of
non-Agbami wells. Accordingly, the maturation of the Ikija appraisal well is being prioritized as a potential candidate for the campaign next year.
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, 2024, 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.
During Q3 2025 the Company continued dialogue with potential partners during its active data room process. Next steps include advancing
potential partnership talks, reviewing potential offers, and aligning forward plans with the government.
Please refer to the Company’s AIF for the year-ended December 31, 2024, for further details on Blocks EG-18 and EG-31.
===== SIDA 24 =====
Report to Shareholders | September 30, 2025
PAGE 18
BUSINESS UPDATE - CONTINUED
EQUITY INVESTMENTS IN ASSOCIATES
As at September 30, 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 September 30, 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 September 30, 2025 55,396,483 449,464,396
Meren’s holding (%) – September 30, 2025 11.56% 39.46%
Meren’s holding (%) – December 31 2024 19.67% 39.46%
Share price (CAD) on September 30, 2025 0.165 -
Exchange rate to USD on September 30, 2025 0.72 -
(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, 2024, 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.
Work is ongoing to integrate the health, safety, environment and communities (HSEC) policies and procedures of the two former businesses.
Previous work undertaken to align the former Meren Coop policies and procedures with those of the former Africa Oil means that this is more
an administrative reorganization than a material change in governance systems.
During the first nine months of 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.
===== SIDA 25 =====
Report to Shareholders | September 30, 2025
PAGE 19
SUMMARY OF QUARTERLY INFORMATION
All financial information included in the narrative discussion below is based on the consolidated statement of net income/(loss) and comprehensive
income/(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
30-Sep
2025
30-Jun
2025
31-Mar
2025
31-Dec
2024
30-Sep
2024
30-Jun
2024
31-Mar
2024
31-Dec
2023
Revenue 216.7 69.3 76.4 - - - - -
Net income/ (loss) attributable to
common shareholders ($’m) 5.2 3.1 50.9 6.2 (289.2) 0.4 3.5 (88.8)
Weighted average shares – Basic ‘000 675,513 675,012 468,472 442,690 442,960 451,231 460,991 462,231
Weighted average shares – Diluted
‘000 682,770 682,039 476,836 449,667 442,960 464,890 474,746 472,942
Basic income / (loss) per share ($) 0.01 0.00 0.11 0.02 (0.65) 0.00 0.01 (0.19)
Diluted income/ (loss) per share ($) 0.01 0.00 0.11 0.02 (0.65) 0.00 0.01 (0.19)
SUMMARY OF KEY ITEMS OF FINANCIAL PERFORMANCE IN THE THREE AND NINE MONTHS ENDED
SEPTEMBER 30, 2025, AND SEPTEMBER 30, 2024
Three months ended Nine months ended
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
Revenue 216.7 - 362.4 -
Gross Profit 55.7 - 114.2 -
General and administrative expenses (9.2) (3.6) (31.4) (19.1)
Net income/ (loss) 5.2 (289.2) 59.2 (285.3)
Revenue
Revenue generated in Q3 2025 and the first nine months of 2025 was $216.7 million and $362.4 million respectively (Q3 2024 and the first
nine months of 2024 – nil) and related to 3 cargoes sold in Q3 2025 at an average price of $70.8/bbl and another 2 cargoes sold in H1 2025
post amalgamation at an average price of $69.2/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/(loss) and comprehensive income/(loss).
Gross profit
Gross profit reported in Q3 2025 and the first nine months of 2025 was $55.7 million and $114.2 million respectively (Q3 2024 and the first
nine months of 2024 – nil). Gross profit was impacted by costs of sales in Q3 2025 and the first nine months of 2025 of $161.0 million and
$248.2 million respectively (Q3 2024 and the first nine months of 2024 – nil) and mainly comprised of depletion costs of $73.0 million and
$155.0 million respectively, net overlift movement in Q3 2025 of $37.3 million and net underlift movement in the first nine months of 2025 of
$17.1 million and costs of operations of $35.3 million and $79.6 million respectively.
===== SIDA 26 =====
Report to Shareholders | September 30, 2025
PAGE 20
SUMMARY OF QUARTERLY INFORMATION - CONTINUED
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 Nine months ended
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
General and administrative expenses 9.2 3.6 31.4 19.1
BTG Oil & Gas transaction related expenses - (0.8) (9.0) (6.2)
Adjusted general and administrative expenses 9.2 2.8 22.4 12.9
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 Q3 2025 and the first nine months of 2025 amounted to $9.2 million and $22.4 million
respectively (Q3 2024 and the first nine months of 2024 - $2.8 million and $12.9 million respectively). Share-based compensation charges
not impacted by the closing of the amalgamation in Q3 2025 and the first nine months of 2025 amounted to $1.3 million and $2.3 million
respectively (Q3 2024 and the first nine months of 2025 – $0.5 million negative and $1.3 million respectively) are impacted by movements in
the share price of the Company.
Adjusted general and administrative expenses excluding share-based compensation charges amounted to $7.9 million in Q3 2025 compared
to $3.3 million in Q3 2024. The increase of $4.6 million is primarily driven by higher costs following the amalgamation and higher headcount.
Adjusted general and administrative expenses excluding share-based compensation charges amounted to $20.1 million in the first nine months
of 2025 compared to $11.6 million in the first nine months of 2024. The increase of $8.5 million is also primarily driven by higher costs following
the amalgamation and higher headcount.
SUMMARY OF KEY ITEMS OF FINANCIAL POSITION AS AT SEPTEMBER 30, 2025, AND DECEMBER 31,
2024
As at
September 30,
2025
December 31,
2024
Assets
Oil and gas properties 1,558.0 -
Intangible exploration assets 41.1 29.3
Equity investments in associates 142.7 177.6
Cash and cash equivalents 176.7 61.4
Outstanding bank debt 360.0 -
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 September 30, 2025, oil and gas properties amounted to $1,558.0 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 September 30, 2025, the carrying amount of the Company’s intangible exploration assets in Equatorial Guinea was $21.7 million (as at
December 31, 2024 – $17.9 million) and related to its 80% interest in Blocks EG-18 and EG-31.
As at September 30, 2025, the carrying amount of the Company’s intangible exploration assets in South Africa was $19.4 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.
===== SIDA 27 =====
Report to Shareholders | September 30, 2025
PAGE 21
Equity investments in associates
As at September 30, 2025, the Company’s investment in associates was $142.7 million compared to an investment value of $177.6 million as
at December 31, 2024. The carrying value of the investments decreased by $34.9 million in the first nine months of 2025 from the Company’s
share of the associates losses of $3.3 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 $141.2 million of the
total equity investments in associates.
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 September 30, 2025, the Company had $176.7 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 $390.0 million of the RBL facility, returned $83.5 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 repaid $390.0 million under the
RBL facility, reducing outstanding bank debt to $360.0 million as at September 30, 2025. RBL facility headroom of $192.3 million at the end
of Q3 2025.
LIQUIDITY AND CAPITAL RESOURCES
As at September 30, 2025, the Company had cash balances of $176.7 million and working capital balances (including cash balances) of $47.5
million, calculated as current assets less current liabilities as presented in the interim condensed consolidated balance sheet as per September
30, 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. 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 September 30, 2025, the BBA was $552.3 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 September 30, 2025.
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.
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Report to Shareholders | September 30, 2025
PAGE 22
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 675,702,593
Outstanding share purchase options 296,616
Outstanding restricted share units 738,620
Outstanding performance share units 6,326,414
Full dilution impact on Common Shares outstanding 683,064,243
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 $0.3 million and $0.8 million was provided in the three and nine months ended September 30,
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 (three
and nine months ended September 30, 2024 - $0.1 million and $0.3 million respectively).
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 Limited, Eco’s
wholly owned subsidiary, in exchange for all common shares and warrants over common shares held by the Company in Eco. On January 13,
2025, the Company announced that it had completed this transaction. The Company’s interest in Block 3B/4B increased by 1.0% to 18.0% and
the Company ceased to be a shareholder in Eco. 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).
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Report to Shareholders | September 30, 2025
PAGE 23
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 $42.5 million in the nine months
ended September 30, 2025.
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 September 30, 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 $150.3 million as per September 30, 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 September 30,
2025, two cargos of the Group’s expected lifted entitlement production for the remainder of 2025 and 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 four cargos covered by forward contracts have been triggered at an average of $63.4 per barrel.
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 year ended
December 31, 2024, and in the Company’s unaudited interim condensed consolidated financial statements for the three and nine months ended
September 30, 2025
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PAGE 24
CRITICAL ACCOUNTING ESTIMATES - CONTINUED
OIL AND GAS PROPERTIES
The Company capitalizes costs related to the acquisition of a license interest, directly attributable general and administrative costs, expenditures
incurred in the process of determining oil and gas exploration targets, and exploration drilling costs. All exploration expenditures that related
to properties with common geological structures and with shared infrastructure are accumulated together within non-producing oil and gas
properties. Costs are held un-depleted until such time as the exploration phases on the license area are complete or commercially viable
reserves have been discovered and extraction of those reserves is determined to be technically feasible. The determination that a discovery is
commercially viable, and extraction is technically feasible requires judgement.
Where results of exploration drilling indicate the presence of hydrocarbons which are ultimately not considered commercially viable, all related
costs are recognized in the Consolidated Statement of net income/(loss) and comprehensive income/(loss). If commercial reserves are established
and technical feasibility for extraction demonstrated, then the related capitalized non-producing oil and gas properties are transferred into the
smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or
groups of assets (CGU) within producing oil and gas properties. The allocation of the Company’s assets into CGUs requires judgement.
Non-producing oil and gas properties are assessed for impairment when they are reclassified to producing oil and gas properties, and also if facts
and circumstances suggest that the carrying amount exceeds the recoverable amount.
The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to dispose. In assessing value in use,
the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of
the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future
cash flows expected to be derived from production of proven and probable reserves. In determining fair value less costs to dispose, recent
market transactions are taken into account, if available. In the absence of such transactions, an appropriate valuation model is used.
The key assumptions the Company uses for estimating future cash flows are the quantity of contingent resources, future commodity prices,
expected production volumes, future operating and development costs, likelihood of a successful farm out process and subsequent timing of
FID and discount rate. The estimated useful life of the CGU, the timing of future cash flows and discount rates are also important assumptions
made by management.
The changing worldwide demand for energy and the global advancement of alternative sources of 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 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 key 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 markets
expectations and the evolving worldwide demand for energy.
EQUITY METHOD
Investments in joint ventures and investments in associates are accounted for using the equity method. Investments of this nature are recorded
at original cost. Investments in joint ventures or associates which arise from a loss in control of a subsidiary are recorded at fair value on the
date of the loss of control. The investment is adjusted periodically for the Company’s share of the profit or loss of the investment after the
date of acquisition. The investor’s share of the profit or loss of the investee is also recognized in the Company’s Consolidated Statement of net
income/(loss) and comprehensive income/(loss). Distributions received reduce the carrying amount of the investment.
IMPAIRMENT OR REVERSAL OF IMPAIRMENT OF JOINT VENTURES AND ASSOCIATES
The amounts for investments in joint ventures and associates represent the Company’s equity interest in other entities, where there is either
joint control or significant influence. The Company assesses investments in joint ventures and associates for an objective evidence of impairment
or reversal of impairment considering changes in circumstances or events which indicate that the carrying value may not be recoverable or
that the carrying value is below the fair value. The process of determining whether there is an objective evidence of impairment or reversal of
impairment or calculating the recoverable amount requires judgement.
CONTINGENT CONSIDERATION
Contingent consideration formed part of the overall consideration for the acquisition of Meren Coop. At the date of acquisition, an estimate of
the contingent consideration is determined and included as part of the cost of the acquisition.
Subsequent to acquisition, contingent consideration can be treated using two acceptable methods, the cost-based approach and the fair value-
based approach. The Company have determined the cost-based approach to give the best estimate of the value of the contingent consideration.
Any revisions to the contingent consideration estimates, after the date of acquisition, are accounted for as changes in estimates in accordance
with IAS 8, to be accounted for on a prospective basis. The change in the liability, as a result of the revised cash flows, would be adjusted to the
cost of the investment and, in accordance with paragraph 37 of IAS 8, recognized as part of the investment’s carrying amount rather than in
profit or loss.
The estimates involved in assessing the value of the contingent consideration include the expected timing of payments, the expected
settlement value, the likelihood of settlement and the probability of the assessed outcomes occurring. There is significant judgement used in
the determination of these estimates.
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Report to Shareholders | September 30, 2025
PAGE 25
CRITICAL ACCOUNTING ESTIMATES - CONTINUED
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 interim condensed 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.
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.
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.
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Report to Shareholders | September 30, 2025
PAGE 26
CRITICAL ACCOUNTING ESTIMATES - CONTINUED
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.
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.
GOING CONCERN
The interim condensed consolidated financial statements for Q3 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.
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Report to Shareholders | September 30, 2025
PAGE 27
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.
In accordance with the provisions of NI 52-109, management, including the Chief Executive Officer and the Chief Financial Officer, have limited
the scope of the design of the Company’s disclosure controls and procedures of Meren Coop. Results for Meren Coop, which was acquired on
March 19, 2025, reflected in the unaudited interim condensed consolidated financial statements and related notes of the Company for the
three months ended September 30, 2025, include current assets of $334.7 million, non-current assets of $1,558.5 million, current liabilities of
$225.5 million, non-current liabilities of $900.3 million as of September 30, 2025, and revenues of $362.4 million and profit before tax of $80.1
million for the period since the transaction closed. The scope limitation is primarily due to the time required for the Company’s management to
assess Meren Coop’s controls and procedures in a manner consistent with the Company’s current operations.
Subject to the scope limitation described above, 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 September 30, 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.
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 September 30, 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.
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Report to Shareholders | September 30, 2025
PAGE 28
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.
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, 2024 (”AIF”) available on SEDAR+ at www.sedarplus.ca or on Meren’s website at www.
mereninc.com/investor-summary/financial-reports-meetings-filings/.
The following additional risks that can materially affect the figures presented and disclosed in the Financial Statement and MD&A have been
identified following completion of the transaction with BTG Oil & Gas to consolidate the interest in Meren Coop.
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.
SIGNIFICANT SHAREHOLDER
BTG Oil & Gas, an investment company which is a subsidiary of BTG Pactual, the largest investment bank in Latin America based in São Paulo,
Brazil, owns approximately 35.5 percent of the aggregate common shares of the Company. BTG Oil & Gas’s holdings may allow it to significantly
affect substantially all the actions taken by the shareholders of the Company, including the election of directors. As long as BTG Oil & Gas
maintains a significant interest in the Company, it is likely that BTG Oil & Gas will exercise significant influence on the ability of the Company to,
among other things, enter into a change in control transaction of the Company and may also discourage acquisition bids for the Company. There
is a risk that the interests of BTG Oil & Gas may not be aligned with the interests of other shareholders.
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Report to Shareholders | September 30, 2025
PAGE 29
FORWARD-LOOKING STATEMENTS
Certain statements in this document may constitute forward-looking information or forward-looking statements under applicable Canadian
securities law (collectively “forward-looking statements”). Forward-looking statements are statements that relate to future events, including
the Company’s future performance, opportunities or business prospects. All statements other than statements of historical fact may be
forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute
forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically
exploited. Any statements that express or involve discussions with respect to expectations, forecasts, assumptions, objectives, beliefs, projections,
plans, guidance, predictions, future events or performance (often, but not always, identified by words such as “believes”, “seeks”, “anticipates”,
“expects”, “continues”, “may”, “projects”, “estimates”, “forecasts”, “pending”, “intends”, “plans”, “could”, “might”, “should”, “will”, “would have” or
similar words suggesting future outcomes) are not statements of historical fact and may be forward-looking statements.
By their nature, forward-looking statements involve assumptions, inherent risks and uncertainties, many of which are difficult to predict, and are
usually beyond the control of management, that could cause actual results to be materially different from those expressed by such forward-
looking statements. Undue reliance should not be placed on these forward-looking statements because the Company cannot assure that
the forward-looking statements will prove to be correct. As forward-looking information addresses future conditions and events, they could
involve risks and uncertainties including, but are not limited to, risk with respect to macro-economic conditions and their impact on operations,
regulations and taxes, civil unrest, corporate restructuring and related costs, capital and operating expenses, pricing and availability of financing
and currency exchange rate fluctuations. Readers are cautioned that the assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-
looking statements.
Forward-looking statements include, but are not limited to, statements concerning:
● A change to the shareholder capital return program including the implementation of share buy-backs;
● The completion and timing of proposed transactions;
● Planned exploration, appraisal and development activity including both expected drilling, and geological and geophysical related activities;
● Potential for an improved economic environment;
● Proposed development plans;
● Future development costs and the funding thereof;
● Expected funding and development costs;
● Anticipated future financing requirements;
● Future sources of funding for the Company’s capital program;
● Future capital expenditures and their allocation to exploration and development activities;
● Expected operating costs;
● Future sources of liquidity, ability to fully fund the Company’s expenditures from cash flows, and borrowing capacity;
● Availability of potential farmout partners/ parties;
● Government or other regulatory consent for exploration, development, farmout, or acquisition activities;
● Future production levels;
● Future crude oil or natural gas prices;
● Future earnings;
● The Company’s ability to deliver further growth and expectations regarding free-cash flow;
● Future asset acquisitions or dispositions and the anticipated strategic and financial benefits of those transactions;
● Future debt levels;
● Availability of committed credit facilities, including existing credit facilities, on terms and timing acceptable to the Company;
● Possible commerciality;
● Development plans or capacity expansions;
● Future ability to execute dispositions of assets or businesses;
● Future drilling of new wells;
● Ultimate recoverability of current and long-term assets;
● Ultimate recoverability of reserves or resources;
● The sustainability of the Company across oil and gas price cycles;
● Future foreign currency exchange rates;
● Future market interest rates;
● Future expenditures and future allowances relating to environmental matters;
● Dates by which certain areas will be explored or developed or will come on stream or reach expected operating capacity;
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Report to Shareholders | September 30, 2025
PAGE 30
FORWARD-LOOKING STATEMENTS - CONTINUED
● The Company’s ability to comply with future legislation or regulations;
● Future staffing level requirements; and
● Changes in any of the foregoing.
Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates
and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in
the future.
These forward-looking statements are subject to known and unknown risks and uncertainties and other factors, which may cause actual results,
levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others:
● Market prices for oil and gas;
● Uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses;
● Changes in exploration or development project plans or capital expenditures;
● The Company’s ability to explore, develop, produce and transport crude oil and natural gas to markets;
● Production and development costs and capital expenditures;
● The imprecise nature of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids;
● Changes in oil prices;
● Availability of financing;
● Uninsured risks;
● Changes in interest rates and foreign-currency exchange rates;
● Regulatory changes;
● Changes in the social climate in the regions in which the Company operates;
● Health, safety and environmental risks;
● Climate change legislation and regulation changes;
● Defects in title;
● Availability of materials and equipment;
● Timelines of government or other regulatory approvals;
● Ultimate effectiveness of design or design modification to facilities;
● The results of exploration, appraisal and development drilling and related activities;
● Short-term well test results on exploration and appraisal wells do not necessarily indicate the long-term performance or ultimate recovery
that may be expected from a well;
● Pipeline or delivery constraints;
● Volatility in energy trading markets;
● Incorrect assessments of value when making acquisitions;
● Economic conditions in the countries and regions in which the Company carries on business;
● Governmental actions including changes to taxes or royalties, and changes in environmental and other laws and regulations;
● The Company’s treatment under governmental regulatory regimes and tax laws;
● Renegotiations of contracts;
● Results of litigation, arbitration or regulatory proceedings;
● Political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict; and
● Internal conflicts within states or regions.
The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors
are interdependent, and management’s future course of action would depend on its assessment of all available information at that time.
Although management believes that the expectations conveyed by the forward-looking statements are reasonable based on the information
available to it on the date such forward-looking statements were made, no assurances can be given that such expectations will prove to be
correct, and such forward-looking statements included in, or incorporated by reference into, this document should not be unduly relied upon.
The forward-looking statements are made as of the date hereof or as of the date specified in the documents incorporated by reference into this
document, as the case may be, and except as required by law, the Company undertakes no obligation to update publicly, re-issue, or revise any
forward-looking statements, whether as a result of new information, future events or otherwise. This cautionary statement expressly qualifies
the forward-looking statements contained herein.
===== SIDA 37 =====
Report to Shareholders | September 30, 2025
PAGE 31
(Expressed in millions of United States dollars)
INTERIM CONDENSED CONSOLIDATED
BALANCE SHEET
As at Note
September 30,
2025
December 31,
2024
ASSETS
Non-current assets
Oil and gas properties 5 1,558.0 -
Intangible exploration assets 6 41.1 29.3
Other tangible fixed assets 4.2 3.2
Equity investment in joint venture 7 - 328.4
Equity investments in associates 8 142.7 177.6
1,746.0 538.5
Current assets
Inventories 9 94.8 -
Investment held for sale 10 - 7.0
Loan to associated company 25 - 4.3
Trade and other receivables 11 111.0 4.0
Cash and cash equivalents 12 176.7 61.4
382.5 76.7
Total assets 2,128.5 615.2
LIABILITIES AND EQUITY
Equity attributable to common shareholders
Share capital 13(B) 1,535.8 1,195.8
Contributed surplus 95.5 87.4
Treasury share account - (0.4)
Deficit (750.0) (734.0)
881.3 548.8
Non-current liabilities
Financial liabilities 15 299.8 2.6
Provisions 14 270.3 49.2
Deferred tax liabilities 342.1 -
912.2 51.8
Current liabilities
Financial liabilities 15 64.3 0.7
Trade and other payables 16 124.2 9.7
Current tax liabilities 48.4 -
Provisions 14 98.1 4.2
335.0 14.6
Total liabilities 1,247.2 66.4
Total liabilities and equity attributable to common shareholders 2,128.5 615.2
The notes are an integral part of the interim condensed consolidated financial statements.
Approved on behalf of the Board:
“MICHAEL EBSARY” “ROGER TUCKER”
MICHAEL EBSARY, DIRECTOR ROGER TUCKER, DIRECTOR
===== SIDA 38 =====
Report to Shareholders | September 30, 2025
PAGE 32
(Expressed in millions of United States dollars)
INTERIM CONDENSED CONSOLIDATED
STATEMENT OF NET INCOME/ (LOSS) AND
COMPREHENSIVE INCOME/ (LOSS)
Three months ended Nine months ended
Note
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
Revenue 19 216.7 - 362.4 -
Cost of Sales
Production costs 20 (88.0) - (93.2) -
Depletion costs 5 (73.0) - (155.0) -
(161.0) - (248.2) -
Gross profit 55.7 - 114.2 -
General and administrative expenses (9.2) (3.6) (31.4) (19.1)
Operating profit/ (loss) 46.5 (3.6) 82.8 (19.1)
Finance income 21 1.2 2.4 3.6 7.5
Finance expense 22 (15.0) (1.3) (35.3) (3.9)
Net financial items (13.8) 1.1 (31.7) 3.6
Share of profit from investment in joint venture 7 - 27.8 2.9 66.7
Share of loss from investments in associates 8 (0.4) (9.5) (2.4) (31.5)
Reversal of impairment/ (impairment) of investment in
joint venture 7 - (305.0) 55.9 (305.0)
Profit/ (loss) before tax 32.3 (289.2) 107.5 (285.3)
Income tax 23 (27.1) - (48.3) -
Net income/ (loss) attributable to common
shareholders 5.2 (289.2) 59.2 (285.3)
Total comprehensive income/ (loss) 5.2 (289.2) 59.2 (285.3)
Net income/ (loss) attributable to common
shareholders per share
Basic 24 0.01 (0.65) 0.10 (0.63)
Diluted 24 0.01 (0.65) 0.10 (0.63)
Weighted average number of shares outstanding for
the purpose of calculating earnings per share
Basic 24 675,512,565 442,960,408 607,202,542 451,651,004
Diluted 24 682,769,598 442,960,408 614,475,355 451,651,004
The notes are an integral part of the interim condensed consolidated financial statements.
===== SIDA 39 =====
Report to Shareholders | September 30, 2025
PAGE 33
(Expressed in millions of United States dollars)
INTERIM CONDENSED CONSOLIDATED
STATEMENT OF EQUITY
For the nine months ended Note
September 30,
2025
September 30,
2024
Share capital: 13(B)
Balance, beginning of the period 1,195.8 1,265.3
Share issuance to BTG Oil & Gas under Amalgamation Agreement 13 353.2 -
Exercise of Share Options 13 - 0.2
Settlement of Restricted Share Units 13 1.1 0.5
Settlement of Performance Share Units 13 2.5 1.1
Weighted average value of shares cancelled 13 (16.8) (59.8)
Balance, end of the period 1,535.8 1,207.3
Contributed surplus:
Balance, beginning of the period 87.4 61.6
Excess of weighted value of shares cancelled 13 8.1 20.0
Balance, end of the period 95.5 81.6
Treasury account:
Balance, beginning of the period (0.4) -
Shares purchased 13 (8.3) 39.8
Shares cancelled 13 8.7 (39.8)
Balance, end of the period - -
Deficit:
Balance, beginning of the period (734.0) (432.3)
Dividends 13 (75.2) (22.6)
Net income attributable to common shareholders 59.2 (285.3)
Balance, end of the period (750.0) (740.2)
Total equity attributable to common shareholders
Balance, end of the period 881.3 548.7
The notes are an integral part of the interim condensed consolidated financial statements.
===== SIDA 40 =====
Report to Shareholders | September 30, 2025
PAGE 34
INTERIM CONDENSED CONSOLIDATED
STATEMENT OF CASH FLOWS
(Expressed in millions of United States dollars)
Three months ended Nine months ended
Note
September 30,
2025
September 30,
2024
September 30,
2025
September 30,
2024
Cash flows generated by/ (used in):
Operations:
Profit/ (loss) before tax 32.3 (289.2) 107.5 (285.3)
Adjustments for:
(Reversal of) impairment of investment in joint venture 7 - 305.0 (55.9) 305.0
Share of loss from investments in associates 8 0.4 9.5 2.4 31.5
Share of profit from investment in joint venture 7 - (27.8) (2.9) (66.7)
Net financial items 21/22 13.8 (1.1) 31.7 (3.6)
Depletion, depreciation and amortisation 5 73.3 - 155.7 -
Taxes (56.1) - (80.5) -
Other 1.9 (1.0) 1.9 (1.7)
Net cash generated/ (used) in operating activities before working
capital 65.6 (4.6) 159.9 (20.8)
Changes in working capital 81.1 (7.4) 33.6 (10.8)
Net cash generated / (used) in operating activities 146.7 (12.0) 193.5 (31.6)
Investing:
Investments in oil and gas properties and intangible
exploration assets 5/6 (21.8) (1.1) (55.8) (6.8)
Investments in other fixed assets - - (0.4) -
Distribution received from joint venture 7 - - 60.0 25.0
Distribution received from associates 8 - - 31.6 -
Equity investment in associates 8 - (27.5) - (27.5)
Loan repaid by / (provided to) associated company 25 - (0.3) 4.5 (0.8)
Interest income received 1.1 1.7 3.6 6.8
Cash acquired from Meren Coop consolidation 4 - - 380.4 -
Net cash (used)/ generated in investing activities (20.7) (27.2) 423.9 (3.3)
Financing:
Repayment RBL Facility (180.0) - (390.0) -
Repayment of principal portion of lease commitments 14 (0.2) (0.1) (0.5) (0.3)
Dividends paid to shareholders (25.1) (11.1) (75.2) (22.6)
Repurchase of share capital 13 - - (8.3) (39.1)
Interest expense paid (10.6) - (28.1) -
Net cash used in financing activities (215.9) (11.2) (502.1) (62.0)
Effect of exchange rate changes on cash and cash
equivalents denominated in foreign currency - 0.9 - 1.0
(Decrease)/ increase in cash and cash equivalents (89.9) (49.5) 115.3 (95.9)
Cash and cash equivalents, beginning of the period 12 266.6 185.6 61.4 232.0
Cash and cash equivalents, end of the period 12 176.7 136.1 176.7 136.1
The notes are an integral part of the interim condensed consolidated financial statements.
===== SIDA 41 =====
Report to Shareholders | September 30, 2025
PAGE 35
NOTES TO INTERIM CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2025, and September 30, 2024
(Expressed in millions of United States dollars unless otherwise indicated)
1. Incorporation and nature of business:
Meren Energy Inc. (collectively with its subsidiaries, “MER” or “Meren” or the “Company” or the “Group”) was incorporated on March 29, 1993,
under the laws of British Columbia and is an international oil and gas exploration and production company based in Canada with oil and gas
interests in Africa. The Company’s registered address is 25th Floor, 666 Burrard Street, Vancouver, B.C., Canada V6C 2X8. The Company changed
its name to Meren Energy Inc on May 14, 2025, and was previously called Africa Oil Corp.
2. Basis of preparation:
A. Statement of compliance:
The Company prepares its interim condensed consolidated financial statements in accordance with Canadian generally accepted accounting
principles for interim periods, specifically International Accounting Standard (“IAS”) 34 Interim Financial Reporting as issued by the International
Accounting Standards Board. They are condensed as they do not include all the information required for full annual financial statements in
accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS Accounting
Standards”) and they should be read in conjunction with the consolidated financial statements for the year ended December 31, 2024.
The policies applied in these interim condensed consolidated financial statements are based on IFRS Accounting Standards and IAS 34.
These interim condensed consolidated financial statements were approved for issuance by the Company’s Board of Directors on November 13,
2025.
B. Basis of measurement:
The interim condensed consolidated financial statements have been prepared on the historical cost basis. Where there are assets and liabilities
calculated on a different basis, this fact is disclosed in the material accounting policy. Identifiable assets acquired and liabilities assumed in the
transaction with BTG Oil & Gas were measured at its acquisition date fair value based on guidance in IFRS 13 as per Note 4. Certain comparative
figures have been reclassified to conform with the financial statements presentation in the current year following completion of the transaction
with BTG. The Company has changed the presentation of its share of profit from investment in joint venture and associated companies in
the interim condensed consolidated statement of net income/(loss) and comprehensive income/(loss). The Company has also changed the
presentation of interest income received in the interim condensed consolidated statement of cash flows.
C. Functional and presentation currency:
These interim condensed consolidated financial statements are presented in United States (US) dollars. The functional currencies of the
Company’s individual entities are US dollars, which represents the currency of the primary economic environment in which the entities operate.
The interim condensed consolidated financial statements are expressed in millions of US dollars unless otherwise indicated.
D. Use of estimates and judgements:
The preparation of financial statements in conformity with IFRS requires management to make judgements, estimates and assumptions that
affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from
these estimates. Items subject to estimates and judgement have been described in the Company’s audited consolidated financial statements
for the year ended December 31, 2024. The following additional items are subject to estimates and judgement following completion of the
transaction with BTG Oil & Gas to consolidate the interest in Meren Coöperatief U.A (previously known as Prime Oil and Gas Coöperatief U.A)
(“Meren Coop”).
Classification of joint arrangements
These interim condensed consolidated financial statements include transactions of non-operated Production Sharing Agreements (‘PSAs’). The
PSA transactions include the Group’s proportionate share of the PSAs assets, liabilities and expenses, with items of a similar nature on a line-
by-line basis, from the date that participation in the PSA arrangements commenced.
The Group has applied judgment in determining that it has joint control over the PSAs. This determination recognizes that all major decisions
outside the original scope of the operations require unanimous approval by at least the Group and one or more of the PSAs partners.
The Group has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions of
the arrangement, such as approval of the capital expenditure program for each year and appointing, remunerating and terminating the key
management personnel or service providers of the joint arrangement. The considerations made in determining joint control are similar to those
necessary to determine control over subsidiaries.
===== SIDA 42 =====
Report to Shareholders | September 30, 2025
PAGE 36
NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
Classifying the arrangement requires the Group to assess its rights and obligations arising from the arrangement. Specifically, the Group
considers:
● The structure of the joint arrangement – whether it is structured through a separate vehicle.
● When the arrangement is structured through a separate vehicle, the Group also considers the rights and obligations arising from:
● The legal form of the separate vehicle;
● The terms of the contractual arrangement; and
● Other facts and circumstances (when relevant).
As the Group has a proportionate share of the rights to the PSAs’ assets and the obligations for the PSAs’ liabilities, it classifies these interests
as a Joint Operation under IFRS 11, and presents its proportionate share of the assets, liabilities, revenues and expenses on a line-by-line basis
in the interim condensed 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.
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.
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.
===== SIDA 43 =====
Report to Shareholders | September 30, 2025
PAGE 37
NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
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.
Going concern
These interim condensed consolidated financial statements for the three and nine months ended September 30, 2025, have been prepared
on a going concern basis, which assumes that the Company will be able to realize its assets and discharge its liabilities in the normal course of
business as they become due.
3. Material accounting policies:
Material accounting policies used in the preparation of these interim condensed consolidated financial statements are described in the Company’s
consolidated financial statements for the year ended December 31, 2024. The following additional material accounting policies have been used
in the preparation of these interim condensed consolidated financial statements following completion of the transaction with BTG Oil & Gas to
consolidate the interest in Meren Coop.
Business combinations
Business combinations are accounted for using the acquisition method as at acquisition date, which is the date on which control is transferred
to the Group. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value
and the amount of any previously held interest in the acquiree.
Acquisition related costs are expensed as incurred and included in general and administrative expenses, except if related to the issue of debt
or equity securities.
When the Group acquires a business, it assesses the assets acquired and liabilities assumed for appropriate classification and designation in
accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. Those petroleum reserves
and resources that are able to be reliably measured are recognized in the assessment of fair values on acquisition. Other potential reserves,
resources and rights, for which fair values cannot be reliably measured, are not recognized.
Any goodwill that arises is tested annually for impairment. Any gain on a bargain purchase is recognized in profit and loss immediately. Goodwill
is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognized for NCI over the
fair value of the identifiable net assets acquired and liabilities assumed. If the fair value of the identifiable net assets acquired is in excess of the
aggregate consideration transferred, the gain is recognized in profit and loss.
After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill
acquired in a business combination is, from the acquisition date, allocated to each of the Group’s CGUs that are expected to benefit from the
combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.
Where goodwill forms part of a CGU and part of the operation in that unit or location is disposed of, the goodwill associated with the disposed
operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed in these
circumstances is measured based on the relative values of the disposed operation and the portion of the CGU retained.
Revenue recognition
Revenue from contracts with customers is recognized when or as the Group satisfies a performance obligation by transferring a promised
good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. As such, revenue
is recognized when control of the goods or service transfers to the customer, it is probable that the economic benefits will flow to the Group
and the revenue can be reliably measured.
The measurement of revenue, when a performance obligation is satisfied, is based on the amount of the transaction price (excluding estimates
of variable consideration that are constrained) that is allocated to that performance obligation, excluding discounts, sales taxes, excise duties
and similar levies.
The Group assesses its revenue arrangements against specific criteria in order to determine if it is acting as principal or agent. If the Group acts
in the capacity of an agent rather than as the principal in a transaction, then the revenue recognized is the net amount of commission made by
the Group. The Group has concluded that it is acting as a principal in all of its revenue arrangements, as described below:
===== SIDA 44 =====
Report to Shareholders | September 30, 2025
PAGE 38
NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
Sales of crude oil and natural gas
Revenue from the sale of crude oil and natural gas is recognized when control of the goods transfers to the customer. The transfer of control
of the crude oil and natural gas sold usually coincides with title passing to the customer and the customer taking physical possession. This
generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism.
Crude oil transaction prices under forward contracts are based on a contract price for the Dated Brent component plus or minus a differential.
In most of the Group’s oil offtake contracts, the Dated Brent component of the forward price at the time of entering the contract is not fixed
but determined on or around the date of the lifting for spot cargos either on an average monthly basis, 5-days after bill of lading date or similar
pricing mechanism. If the Group wants to utilize the oil offtake contract for commodity risk management, it can either fix the Dated Brent
component or utilize a trigger pricing mechanism. For the trigger pricing mechanism, when the forward price curve falls below a certain trigger
price for a certain month, this mechanism provides an irrevocable instruction to an offtaker to fix the Dated Brent price component of a cargo.
The trigger price is based on a percentage of the Brent forward curve at the time the instruction was given for the month of the expected lifting.
If the forward price curve does not fall below that threshold, the respective cargo is sold at spot.
The performance obligation is satisfied and payment is due upon delivery, FOB, to the buyer. At this point in time, at the bill of lading date, a
trade receivable is recognized and there are generally 30 days between revenue recognition and payment. There are no obligations for returns,
refunds, warranties nor other obligations when control has been transferred. The Group principally satisfies its performance obligations at a
point in time.
Revenue from crude oil transactions not covered under oil offtake contracts, arises from the production and lifting of crude oil on an entitlements
basis. Under the entitlements method, revenue reflects the Group’s share of production under the terms of the relevant production sharing
contracts, regardless of which participant has actually made the sale and invoiced the production. This is achieved by applying the following
approach in dealing with imbalances between actual sales and entitlements.
● Crude oil entitlement underlifts are recognized at the market price of oil at the balance sheet date. The excess of product sold during the
period over the participant’s ownership share of production is recognized by the Group (acting as underlifter) as an asset in trade and other
receivables with a corresponding credit to production costs. The Group’s underlift receivable is the right to receive additional oil from future
production without the obligation to fund the production of that additional oil.
● Crude oil entitlement overlifts are treated as a purchase of crude oil by the overlifter from the underlifter and are also recognized at the
market price of oil at the balance sheet date. The excess of product purchased during the period over the participant’s ownership share
of production is recognized by the Group (acting as overlifter) as a liability in trade and other payables with a corresponding charge to
production costs. An overlift liability is the obligation to deliver oil out of the Group’s equity share of future production.
Revenues resulting from the production of oil under PSAs is recognized for those amounts relating to the Group’s cost recoveries and the
Group’s share of the remaining production.
Royalties
Obligations arising from royalty arrangements and other types of taxes that do not satisfy the criteria of IAS 12 ‘Income Taxes’ are accrued
or paid and included in production costs. This is considered to be the case when the royalties are imposed under government authority and
the amount payable is based on physical quantities produced or as a percentage of revenue, rather than taxable income. In some cases, the
equivalent amount of royalties is also presented in revenues to differentiate between the portion of revenue lifted by the operator on behalf of
the Group to settle the Group’s royalty liabilities and the associated royalties as part of production costs. In cases where the Group itself pays
for the royalties in cash, these are included in production costs as a single line item.
Production costs
The costs of producing oil are charged to the income statement in the period in which they are incurred. Production costs include movements
in underlift and overlift balances.
Depletion costs
Oil and gas properties are depreciated from the commencement of production, on a UoP basis, which is the ratio of oil and gas production in
the period to the estimated quantities of the 2P reserves at the end of the period plus the production in the period, on a field-by-field basis.
Facilities included in oil and gas production assets are depreciated on a UoP basis over the economic useful life of the field concerned. Costs
used in the UoP calculation comprise the net carrying amount of capitalized costs plus the estimated future field development costs. Changes
in the estimates of reserves or future field development costs are dealt with prospectively. Oil and gas volumes are considered produced once
they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the field storage tank. Rights
and concessions are depleted on the UoP basis over the total proved and probable reserves of the relevant area.
Derivative financial instruments and hedge accounting
The Group is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is
commodity price risk.
The Group uses forward commodity contracts to hedge its commodity price risk. On the forward commodity contracts hedge accounting is not
considered applicable as the own-use exception applies: the Group does not enter into physical oil contracts other than to meet the Group’s
expected sales requirements. These arrangements therefore fall outside the scope of IFRS 9 and are classified as normal sales contracts that
are accounted for on an accrual basis.
The Group’s derivative financial instruments are initially recognized at fair value on the date on which the derivative contracts are entered into
and are subsequently remeasured at fair value, with subsequent changes in fair value recognized in other comprehensive income. Derivatives
are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative.
===== SIDA 45 =====
Report to Shareholders | September 30, 2025
PAGE 39
NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
Inventories
Inventories mainly comprise materials. These are stated at the lower of cost and net realizable value. Purchase cost includes costs of bringing
material inventory to their present location and condition, including freight and handling charges. Cost is determined using the weighted average
method. Net realizable value is the estimated selling price in the ordinary course of business, less selling expenses.
If carrying value exceeds the net realizable amount, a write down is recognized. The write-down may be reversed in a subsequent period if the
circumstances which caused it no longer exist.
Trade receivables
Trade receivables are amounts due from customers for crude oil and gas sold or services performed in the ordinary course of business and
represent the Group’s right to an amount of consideration that is unconditional (i.e., only the passage of time is required before payment of the
consideration is due). Trade receivables are recognized initially at fair value and subsequently measured at amortized cost using the effective
interest method, less any allowance for expected credit losses.
Dividends
Dividend liabilities are recognized when the Company’s shareholders have the right to receive the payment when the dividend is approved by
the Board of Directors of the Company.
New accounting standards
On January 1, 2025, the Company adopted the amendments to IAS 21 - Lack of Exchangeability. The amendments help entities to determine
whether a currency is exchangeable into another currency, and which spot exchange rate to use when it is not. There was no material impact
to the Company’s financial statements.
On April 9, 2024, the International Accounting Standards Board (IASB) issued IFRS 18 Presentation and Disclosure in Financial Statements,
which aims to improve how companies communicate their financial statements, with a focus on information about financial performance in the
statement of profit or loss. IFRS 18 is effective January 1, 2027. The Company is in the process of assessing the impact that the standard will
have on its financial statements.
Other new accounting standards and amendments to accounting standards have been published that are not mandatory for September 30,
2025, reporting periods and have not been early adopted by the Company. These are as follows:
● Amendments to the Classification and Measurement of Financial Instruments – Amendments to IFRS 9 and IFRS 7 (effective for annual
periods beginning on or after 1 January 2026);
● Annual improvements to IFRSs: Volume 11 (effective for annual periods beginning on or after 1 January 2026);
● IFRS 19 Subsidiaries without Public Accountability: Disclosures (effective for annual periods beginning on or after 1 January 2027); and
These amendments are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable
future transactions.
4. Business combination:
On March 19, 2025, the Company completed the transaction with BTG Oil & Gas to consolidate its interest in Meren Coop. The transaction
was originally announced on June 24, 2024. The acquisition increased the Company’s ownership in core cash generating assets and brought
in a new, strategically aligned cornerstone investor, BTG Pactual. It is also expected to enable enhanced shareholder returns and the creation
of a materially stronger growth proposition. The acquisition was completed by way of amalgamation whereby BTG Oil & Gas exchanged its 50
percent interest in Meren Coop, held through its fully owned subsidiary BTG Pactual Holding S.à.r.l., in exchange for 239,828,655 newly issued
shares in the Company. The primary assets acquired are an indirect 8% interest in Petroleum Mining License ("PML") 52 and an indirect 16%
interest in PMLs 2, 3 and 4 as well as Petroleum Prospecting License ("PPL") 261. PML 52 is operated by affiliates of Chevron and covers part
of the producing Agbami field. PMLs 2, 3 and 4 and PPL 261 are operated by affiliates of TotalEnergies and contain the producing Akpo and
Egina fields.
The acquisition date for accounting purposes corresponds to the completion of the transaction on March 19, 2025. The acquisition is regarded
as a business combination and has been accounted for using the acquisition method of accounting in accordance with IFRS 3. A purchase price
allocation (“PPA’’) has been performed to allocate the consideration to fair value of assets acquired and liabilities assumed. The PPA is performed
as of the acquisition date. The closing share price of CAD 2.09 and closing USD/CAD currency exchange rate of 1.4193 on March 19, 2025, were
used as a basis for measuring the value of the consideration, as set forth below, and includes the Company’s previously held 50% interest in
Meren Coop prior to March 19, 2025.
Expressed in millions of United States dollars
Value of share consideration to BTG Oil & Gas 353.2
Value of previous interest held in Meren Coop 327.8
Total value of consideration 681.0
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Report to Shareholders | September 30, 2025
PAGE 40
NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 13. Trade receivables are recognized
at gross contractual amounts due, as they relate to large and credit-worthy customers. Historically, there has been no significant uncollectible
trade receivables in Meren Coop.
The recognized amounts of assets and liabilities assumed as at the date of acquisition were as follows:
Preliminary purchase price allocation
March 19, 2025
Assets acquired
Oil and gas properties 1,538.1
Inventories 95.4
Indemnity asset (note 14) 21.6
Trade and other receivables 233.5
Cash and cash equivalents (1) 380.4
Total assets acquired 2,269.0
Liabilities assumed
Non-current financial liabilities 451.5
Non-current provisions 132.2
Deferred tax liabilities 374.3
Current financial liabilities 298.5
Trade and other payables 164.6
Current tax liabilities 112.3
Current provisions (note 14) 54.6
Total liabilities assumed 1,588.0
Net assets and liabilities recognized 681.0
Value of share consideration to BTG Oil & Gas 353.2
Value of previously held interest in Meren Coop (note 7) 327.8
Total value of consideration 681.0
(1) Cash and cash equivalents includes $59.1 million of cash held in the amalgamated company.
In the period from the acquisition date to September 30, 2025, the revenue and profit included in the interim condensed consolidated statement
of net income/(loss) and comprehensive income/(loss) relating to the acquired entities was $362.4 million and $31.8 million respectively.
Acquisition-related costs for the year ended December 31, 2024, and the nine months ended September 30, 2025, were included in general and
administrative expenses and amounted to $6.9 million and $9.0 million, respectively.
If the acquisition had taken place on January 1, 2025, the estimated revenue and income of the combined Group for the nine months ended
September 30, 2025, would have been approximately $685.9 million and $8.1 million respectively. These figures may not be indicative of the
results that would have been achieved if the acquisition had actually taken place on January 1, 2025.
The purchase price allocation above is preliminary and based on current available information about fair values as of the acquisition date. If
new information becomes available within 12 months from the acquisition date, the Group may change the fair value assessment in the PPA, in
accordance with guidance in IFRS 3.
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Report to Shareholders | September 30, 2025
PAGE 41
NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
5. Oil and gas properties:
Nigeria
At January 1, 2025 -
Acquired under amalgamation 1,538.1
Remeasurement of site restoration provisions 122.9
Additions 52.0
Depletion (155.0)
At September 30, 2025 1,558.0
As at September 30, 2025, oil and gas properties amounted to $1,558.0 million and related to the licenses PML 52 (covering part of the Agbami
field), PML 2 (Akpo field), PML 3 (Egina field) and PML 4 (Preowei Field) in Nigeria.
The Company recognized a change in estimate of $122.9 million in oil and gas properties relating to the remeasurement of the site restoration
provisions acquired under the amalgamation in accordance with IAS 37 (see note 14).
6. Intangible exploration assets:
Intangible exploration assets
Equatorial Guinea South Africa Total
At January 1, 2024 13.4 5.7 19.1
Additions 4.5 5.7 10.2
At December 31, 2024 17.9 11.4 29.3
Additions 3.8 8.0 11.8
At September 30, 2025 21.7 19.4 41.1
As at September 30, 2025, the carrying amount of the Company’s intangible exploration assets in Equatorial Guinea was $21.7 million and
related to its 80% interest in Blocks EG-18 and EG-31 (as at December 31, 2024 – $17.9 million).
As at September 30, 2025, the carrying amount of the Company’s intangible exploration assets in South Africa was $19.4 million for its 18.0%
(as at December 31, 2024 – 17.0%) participating interest in the Block 3B/4B Exploration Right (as at December 31, 2024 - $11.4 million).
On July 26, 2024, the Company signed an agreement with Eco to acquire an additional 1.0% interest in Block 3B/4B from Azinam Limited, Eco’s
wholly owned subsidiary, in exchange for all common shares and warrants over common shares held by the Company in Eco. On January 13,
2025, the Company announced that it had completed this transaction. The Company’s interest in Block 3B/4B increased by 1.0% to 18.0%
and the Company ceased to be a shareholder in Eco. The fair value of the Company’s investment in Eco on the day of the transaction was $8.0
million, which has been recorded as an addition to intangible exploration assets.
7. Equity investment in joint venture:
Meren Coöperatief U.A (previously known as Prime Oil and Gas Coöperatief U.A.) (“Meren Coop”):
On March 19, 2025, the Company announced the completion of the amalgamation with BTG Oil & Gas (“the amalgamation) to consolidate the
remaining 50% interest in Meren Coop in exchange for 239,828,655 common shares issued in Meren. Following completion of the amalgamation,
Meren Coop is fully consolidated by the Company as from March 19, 2025 (see Note 4).
The following table shows the Company’s carrying value of the non-controlling 50% interest in Meren Coop as at September 30, 2025, and
December 31, 2024. The carrying value as per March 19, 2025, of $327.8 million has been assigned to the fair value of assets acquired and
liabilities assumed as per Note 4.
September 30,
2025
December 31,
2024
Balance, beginning of the period 328.4 572.5
Share of joint venture profit 2.9 226.0
Distributions received from Meren Coop (60.0) (36.0)
Revaluation of contingent consideration 0.6 2.6
Reversal of impairment / (Impairment) 55.9 (436.7)
Impact of amalgamation (327.8) -
Balance, end of the period - - 328.4
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