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===== SIDA 1 =====

For the Year Ended December 31, 2025
Q4
25
Meren Energy Inc. (previously called Africa Oil Corp.)
Report to  
Shareholders

===== SIDA 2 =====

Report to Shareholders  |  December 31, 2025
PAGE 2
A
“Africa Energy” means Africa Energy Corp. an international oil and gas exploration company that holds an effective 4.9% 
participating interest in the Exploration Right for Block 11B/12B offshore South Africa.
“Amalgamation”
means the amalgamation transaction whereby BTG Oil & Gas exchanged its 50 percent interest in Meren 
Coop, held through its fully owned subsidiary BTG Pactual Holding S.à.r.l., in exchange for 239,828,655 
newly issued shares in the Company.
“Applicable law” means all laws and regulations issued by authorities that have appropriate jurisdiction over the Company.
“Azinam” means Azinam Limited, a wholly owned subsidiary of Eco.
B
“Bcf” means billion cubic feet.  
“boepd” means barrels of oil equivalent per day.
“BTG Holding” means BTG Pactual Holding S.a.r.l.
“BTG Oil & Gas” means BTG Pactual Oil & Gas S.a.r.l.
C
“CGU”
means Cash Generating Unit. A Cash Generating Unit is defined as assets that are grouped together into 
the smallest group of assets that generates cash inflows from continuing use that are largely independent 
of the cash inflows of other assets or groups of assets.
“Chevron” means Chevron Corp.
“CIT” means Corporate Income Tax.
“Concessions”
means concessions, PSAs, PSCs and other similar agreements entered into with a host government 
providing for petroleum operations in a defined area and the division of petroleum production from the 
petroleum operations.
D “DD&A” means Depreciation, Depletion and Amortization.
E
“EBITDAX” means Earnings Before Interest, Taxes, Depreciation & Impairment, Amortization and Exploration 
Expenses. 
“Eco” means Eco (Atlantic) Oil & Gas Ltd.
“Entitlement 
production”
means production that is calculated using the economic interest methodology and includes cost oil, profit 
oil, tax oil and royalty oil.
“ESIA” means Environmental and Social Impact Assessment.
F
“FEED” means Front End Engineering and Design. 
“FID” means Final Investment Decision.
“FPSO” means Floating Production Storage and Offloading.
G
“GHG” means Greenhouse Gas. 
“GTCs” means Gas Turbine Compressors.
I
“IFRS Accounting 
Standards” 
means International Financial Reporting Standards as issued by the International Accounting Standards 
Board. 
“Impact” 
means Impact Oil and Gas Ltd, a privately owned exploration company with a strategic focus on large 
scale, mid to deep water plays of sufficient materiality to be of interest to major companies. Impact has an 
asset base across the offshore margins of Southern and West Africa.
J “JV” means Joint Venture.
K “Kenya entities” means Centric Energy Kenya Limited, Africa Oil Kenya B.V Branch and Africa Oil Turkana Limited.
L “LTIP” means Long Term Incentive Plan.
GLOSSARY

===== SIDA 3 =====

Report to Shareholders  |  December 31, 2025
PAGE 3
M
“Mcf” means million cubic feet. 
“Meren”, “MER”, or the 
“Company” means Meren Energy Inc.
“Meren Coop” or “Meren 
Coöperatief U.A.”
means Meren Coöperatief U.A., previously known as Prime Coöperatief U.A., a company that holds interests 
in deepwater Nigeria production and development assets.
“Meren 52” means Meren Nigeria 52 Limited (previously named Prime 127 Nigeria Limited).
“Meren 234” means Meren 234 Nigeria Limited (previously named Prime 130 Nigeria Limited).
“MD&A” means Management’s Discussion and Analysis.
“Mbbl” and “MMbbl” means one thousand and one million barrels, respectively.
“Mboe” and “MMboe” means thousands of barrels of oil equivalent and millions of barrels of oil equivalent, respectively.
N
“NCIB” means Normal Course Issuer Bid. 
“NI 51-101” means National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities of the Canadian 
Securities Administrators and the companion policies and forms thereto, as amended from time to time.
“NI 52-109” means National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings and 
the companion policies and forms thereto, as amended from time to time.
“NUPRC” means Nigerian Upstream Petroleum Regulatory Commission. 
P
“PIA” means Petroleum Industry Act.
“PML” means Petroleum Mining Lease.
“PML 2” means the Petroleum Mining Lease containing the Akpo field.
“PML 3” means the Petroleum Mining Lease containing the Egina field.
“PML 4” means the Petroleum Mining Lease containing the Preowei field.
“PML 52” means the Petroleum Mining Lease containing the Agbami field.
“PPL” means Petroleum Prospecting License.
“PPL 2003” means the Petroleum Prospecting License containing the Ikija prospect
“PPL 261” means the Petroleum Prospecting License containing the South Egina prospect.
“PPT” means Profit Petroleum Tax.
“PRMS” means Petroleum Resources Management Reporting System.
“PSA” means Production Sharing Agreement.
“PSC” means Production Sharing Contract.
“PSU” means Performance Share Unit.
R
“RBL” means Reserves Based Lending.
“RSU” means Restricted Share Unit.
S
“SOFR” means Secured Overnight Financing Rate.
“spud” or “spudded” means the initial drilling for an oil well.
T
“TAM” means planned turnaround maintenance.  
“TotalEnergies” means TotalEnergies SE and subsidiaries. 
“TSX” means Toronto Stock Exchange.
U “US” means United States.
W
“WI”  means working interest.
“WI production”  means production based on the percentage of working interest owned.

===== SIDA 4 =====

Report to Shareholders  |  December 31, 2025
PAGE 4
MANAGEMENT’S DISCUSSION AND ANALYSIS
The Management’s Discussion and Analysis (“MD&A”) focuses on significant factors that have affected the Company during the year ended 
December 31, 2025, and such factors that may affect its future performance. To better understand the MD&A, it should be read in conjunction 
with the Company’s audited consolidated financial statements for the years ended December 31, 2025, and 2024, and related notes thereto. 
The financial information in this MD&A is derived from the Company’s audited consolidated financial statements which have been prepared in 
US dollars, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS 
Accounting Standards”). 
This MD&A was reviewed and approved by the Board of Directors. The effective date of this MD&A is February 24, 2026. 
Additional information about the Company and its business activities is available on the Company’s website at www.mereninc.com and on 
SEDAR+ at www.sedarplus.com.
The Company changed its name to Meren Energy Inc. on May 14, 2025, and was previously called Africa Oil Corp.
PROFILE AND STRATEGY
Meren is a Canadian oil and gas company with producing and development assets in deep-water offshore Nigeria. The Company also has a 
portfolio of development and exploration assets in West and South of Africa. 
The Company’s Common Shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in Sweden, under 
the symbol ‘MER’. 
The Company’s common shares also trade on the OTCQX Best Market (“OTCQX”) in the U.S. under the ticker ‘MRNFF’. 
Meren’s strategy is anchored in maintaining a resilient balance sheet through the cycle, prioritizing high-return organic investment in its core 
assets, and delivering sustainable shareholder returns from surplus free cash flow. This plan is supported by the Company’s high netback 
production assets in Nigeria that are included in its interests in Petroleum Mining Leases (“PMLs”) 2, 3, 4 and 52. These PMLs provide the Company 
with a long-life cash flowing asset base, to support its business objectives over the long term, and also present development opportunities for 
supporting future production together with the Company’s interests in Petroleum Prospecting Licenses (“PPLs”) 261 and 2003. 
The Company’s other core assets are comprised of its Orange Basin opportunity set including Blocks 2912 and 2913B offshore Namibia and 
Block 3B/4B, offshore South Africa, as well as Equatorial Guinean exploration and appraisal blocks (EG-18 and EG-31).
The Company is a unique investment opportunity, amongst its publicly-listed independent E&P peer group, for its Orange Basin opportunity set 
that includes an effective interest in the Venus light oil and associated gas discovery offshore Namibia. The Venus discovery, understood to 
be the largest oil discovery globally in 2022, has partially de-risked a new petroleum province in the Orange Basin that has significant further 
prospectivity.
HIGHLIGHTS AND OUTLOOK 
Full-Year 2025, Q4 2025 AND POST PERIOD HIGHLIGHTS
 ● During 2025, closed the transformative Prime amalgamation to take full control of Prime’s assets, doubling Meren’s reserves and production; 
 ● Distributed approximately $100 million to the Company’s shareholders under the base dividend policy and repurchased 5.9 million shares at 
a cost of approximately $8 million;
 ● Achieved average daily W.I and entitlement production of 30,800 boepd and 35,100 boepd, respectively, for 2025, in line with the revised 
full-year management guidance;
 ● Sold three cargos in Q4 2025 at an average sales price of $64.4/bbl and twelve cargos in 2025 at an average sales price of $72.2/bbl, both 
of which were higher than average Dated Brent for the same periods;
 ● In 2025 reduced the RBL by $420.0 million, reducing interest expenses and ending 2025 with a debt balance of $330.0 million. 
 ● End of 2025 cash balance of $174.7 million resulting in a net debt position of $155.3 million with a Net Debt/ EBITDAX of 0.4x as at 
December 31, 2025, with a RBL facility headroom of $138.4 million.
 » EBITDAX of $440.7 million;
 » Cashflow from operations before working capital adjustment of $261.8 million; and
 » Cash capital investments of $100.2 million.
 ● Reported net loss of $31.6 million ($0.05/share) for full-year 2025, primarily from to a non-cash impairment of $105.3 million for the 
Agbami cash generating unit (“CGU”) reflecting a more conservative oil price and cost outlook compared to prior assumptions.
 ● Following continued strong operating performance and after consideration of organic investment requirements and balance sheet resilience, 
the Board has declared the first quarterly dividend in 2026 of approximately $25.1 million;
 ● On February 2, 2026, the Company announced that Roger Tucker had stepped down from the role of President and CEO and as a director 
of Meren, and that Oliver Quinn had been appointed as his successor and joined the Board as a director.

===== SIDA 5 =====

Report to Shareholders  |  December 31, 2025
PAGE 5
 ● Meren’s year-end 2025 reserves:
 » YE’25 reserves determination has delivered after-tax 1P NPV(10) and 2P NPV(10) valuations of $588 million (YE’24: $1,248 million) and 
$1,499 million (YE’24: $2,128 million) respectively.
 » YE’25 W.I. and net entitlement7 1P reserves of 48.8 MMboe (YE’24: 59.8 MMboe) and 62.5 MMboe (YE’24: 70.8 MMboe), respectively.
 » YE’25 W.I. and net entitlement 2P reserves of 87.7 MMboe (YE’24: 101.6 MMboe) and 107.4 MMboe (YE’24: 116.4 MMboe), respectively.
 » YE’25 aggregate W.I. 2P reserves and 2C contingent resources of 140.2 MMboe (YE’24: 129.6 MMboe).
FINANCIAL SUMMARY (1)
Three months ended Years ended
Meren highlights Unit
December 31, 
2025
December 31, 
2024
December 31, 
2025
December 31, 
2024
Net (loss)/ income $’m (90.8) 6.2 (31.6) (279.1)
Net (loss)/ income per share – basic (2) $/ share (0.13) 0.02 (0.05) (0.62)
Net debt position (3) $’m 155.3 289.1 155.3 289.1
WI production (3) boepd 28,100 34,400 30,800 34,000
Entitlement production (3) boepd 31,500 39,000 35,100 38,800
Cash flow from operations (4, 5) $’m 18.7 n/a 261.8 n/a
EBITDAX (4) $’m 72.7 n/a 440.7 n/a
Capital investments (4) $’m 19.8 n/a 100.2 n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on pages 14 - 17.
(2) Based on the weighted average number of shares outstanding for the three months and year ended December 31, 2025, of 675,685,556 and 
624,464,015 respectively, which accounts for the newly issued shares to BTG Oil & Gas on March 19, 2025.
(3) Net debt position and production numbers as presented for the comparative periods includes 100 percent of Meren Coop to be comparable with net 
debt position and production numbers for the three months and year ended December 31, 2025.  
(4) Highlights are reported for the year 2025 only, on a constructed financial information basis, see pages 10 - 12 for further information.
(5) Cash flow from operations before working capital and interest payments.
OUTLOOK
Nigeria
Nigeria’s macroeconomic and sector-specific reforms are beginning to show tangible results, with improved fiscal clarity, stronger government 
engagement, and targeted incentives aimed at sustaining investment in the oil and gas sector. The Federal Government has reaffirmed its 
support for upstream development through regulatory stability and commercial incentives, contributing to renewed capital commitment across 
offshore oil and gas projects. This improved investment climate is evidenced by recent final investment decisions on major developments such 
as Bonga North, Ubeta Gas Project, and HI Offshore Gas Project, which collectively signal growing confidence in Nigeria as a destination for 
long-term energy investment.
In collaboration with its JV Parties, the Company is continuing to advance the restart of the Akpo/Egina 2026 drilling campaign following the 
break in the 2025 program. Work is underway to secure a deepwater rig with the drilling of the Akpo Far East near-field prospect, the first 
planned well in the campaign. This will be followed by the drilling of further infill development wells in the Akpo and Egina fields in late 2026 
and into early 2027. Notably, the pause in the drilling program has created a valuable opportunity for the interpretation of 4D seismic data 
focused on the maturation of infill well candidates. 
The Akpo Far East prospect presents a strategically positioned fast-cycle tie-back opportunity that will utilise the existing Akpo facilities. The 
prospect lies about 5 km east of the currently producing Akpo field and the planned drilling approach will assess all prospective resource 
volumes identified within the prospect. To support this, efforts are ongoing to complete all the work required to spud the Akpo Far East 
exploratory well in 2026.

===== SIDA 6 =====

Report to Shareholders  |  December 31, 2025
PAGE 6
HIGHLIGHTS AND OUTLOOK  - CONTINUED
Work is actively progressing on the remaining subsurface and development opportunities within the PML 2/3/4 license area. Preowei Field 
subsurface review and development validation activities continued in Q4 2025 with study results expected in H1 2026 to guide the timing and 
scope of an FID. The planned appraisal activity by TotalEnergies in the Egina South area in OPL 257, currently expected in 2026, may further 
de-risk adjacent resources and, if successful, indicate potential additional value for Meren through proximity to existing infrastructure.
In early 2026, Meren and its JV Parties in PML 2/3 successfully executed an amendment to the gas sales agreement that includes a revised 
index for gas pricing, locking in a long-term gas price that is more reflective of the current LNG economics compared to 2018 when the contract 
was initially signed. The amendment also includes a mechanism for the sellers to recover the historical difference between the interim gas price 
adjustment and the new index, starting from 2020 when the previous index ceased to be published. This historical amount will be recovered 
through an upward adjustment to the netback pricing that includes the handling fee for the gas sold.  
In Agbami the FPSO unit life extension studies, to ensure long term asset integrity and to enhance operation performance of the facility are 
expected to conclude in 2026. Also, the ongoing 4D seismic interpretation and rig contracting activities for the Agbami infill drilling program 
remain on schedule. The Agbami infill drilling campaign is expected to commence in Q1 2027, following the planned arrival of the rig in Q4 2026 
with the Ikija appraisal well being matured to initiate the campaign as the first well.
Namibia Orange Basin Development and Exploration, Blocks 2912 and 2913B
The Venus Field in Block 2913B remains the most advanced deepwater discovery in the Orange Basin and is expected to anchor Namibia’s first 
large-scale offshore oil development. The project is being progressed by TotalEnergies (Operator, 50.5%) together with QatarEnergy (30.0%), 
NAMCOR (10.0%) and Impact Oil & Gas (9.5%). Through its shareholding in Impact, Meren holds an effective 3.8 percent indirect interest in 
the Venus development. Under Impact’s carried-interest arrangement with TotalEnergies, Meren’s exposure to all development and exploration 
costs on Blocks 2912 and 2913B remains fully funded through to first commercial production, without any financial cap.
The Environmental and Social Impact Assessment (ESIA) for the proposed Venus development has been completed and published, and the 
associated Environmental Clearance Certificate (ECC) application has been submitted to the relevant Namibian authorities. Completion of the 
ESIA represents a key regulatory milestone, further de-risking the project. FEED work is proceeding on the base-case concept of up to 40 subsea 
wells tied back to a single FPSO with a nameplate capacity of approximately 160,000 barrels per day of oil, with reinjection of associated gas 
offshore. Contractor bids have been received and are within expectation. The project schedule remains consistent with the current planning 
framework with FID targeted for 2026 and first oil in 2030, subject to the completion of negotiations between the operator and the government 
on enhanced fiscal terms for the project, which is expected to be the first producing oil field and the first deepwater development in Namibia. 
The Venus development is regarded by the Namibian government as a strategic national project with the potential to establish Namibia as a 
new deepwater oil producer. Appraisal and exploration activities continue across the broader Orange Basin and additional prospects are being 
evaluated using newly acquired 3D seismic data on Blocks 2912 and 2913B.
Namibia’s oil and gas sector remains active and supportive, with strong investment from international operators, rollout of a Local Content 
Policy, and infrastructure upgrades at the Walvis Bay and Lüderitz ports. Execution and infrastructure challenges, including marine services 
capacity, environmental approvals, and gas monetization, present both risks and opportunities as the country positions itself to attract capital 
and expand its deepwater supply chain.
The Venus development presents Meren with a material long-term growth opportunity within a fully carried structure, offering potential for 
future cash-flow generation and portfolio optionality with no upfront funding commitments.
South Africa Orange Basin, Block 3B/4B
On September 16, 2024, the Department of Mineral Resources and Energy for the Republic of South Africa granted an Environmental 
Authorization for exploration activities (drilling of up to 5 exploration wells) on the block. Following that decision, the legislative notification 
and appeals process in South Africa was suspended pending a Supreme Court of Appeal judgement in respect of Block 5/6/7. The operator has 
stated that the current plan is to drill the first exploration well on Block 3B/4B as soon as the Environmental Authorization is confirmed and 
has identified Nayla, a prospect that lies in the northwest of the license area, as the potential drilling target.
Equatorial Guinea, Blocks EG-18 and EG-31
In late 2025 the Company submitted requests for extensions to the exploration license terms for both blocks. On December 17, 2025, the 
Company received notification from the Ministry of Hydrocarbons and Mining Development in Equatorial Guinea approving extensions of up to 
two years to the first exploration sub period on each block.
During the course of 2025, the company completed a number of data room exercises across the two blocks and remains actively engaged 
in advancing potential partnership discussions. Following industry interest during the data room phase, the Company is now transitioning into 
the next stage of activity, focused on advancing discussions with prospective partners. In parallel, the Company continues to coordinate with 
government and representatives from GEPetrol to define the forward plan for both blocks.
Should the Company successfully attract a farm-in partner(s) on acceptable terms for these blocks, subject to customary consents and 
approvals including governmental and regulatory permissions, the Company anticipates that newly formed JVs could be positioned to plan for 
appraisal and development as well as exploration drilling in late 2026 or 2027. 
While there can be no assurance of securing partners on acceptable terms, the Company remains encouraged by the level of industry interest 
and continues to advance partnership discussions with confidence.

===== SIDA 7 =====

Report to Shareholders  |  December 31, 2025
PAGE 7
HIGHLIGHTS AND OUTLOOK  - CONTINUED
Shareholder Returns
The Company’s capital allocation framework balances reinvestment in value-accretive organic opportunities with a commitment to sustainable 
shareholder returns, while preserving balance sheet strength and financial flexibility.
Following continued strong operating performance and after consideration of organic investment requirements and balance sheet resilience, 
the Company is pleased to announce that its Board has declared the distribution of the Company’s first quarterly cash dividend in 2026 of 
approximately $25.1 million or $0.0371 per share. This dividend will be payable to shareholders of record at the close of business on March 
20, 2026. 
This dividend qualifies as an ‘eligible dividend’ for Canadian income tax purposes. Dividends for shares traded on the Toronto Stock Exchange 
(“TSX”) will be paid in Canadian dollars on April 7, 2026; however, all US and foreign shareholders will receive USD funds. Dividends for shares 
traded on Nasdaq Stockholm will be paid in Swedish Krona in accordance with Euroclear principles at the earliest on April 10, 2026.
To execute the payment of the dividend, a temporary administrative cross border transfer closure will be applied by Euroclear from March 18, 
2026, up to and including March 20, 2026, during which period shares of the Company cannot be transferred between the TSX and Nasdaq 
Stockholm. 
Payment to shareholders who are not residents of Canada will be net of any Canadian withholding taxes that may be applicable. For further 
details, please visit: https://mereninc.com/investor-summary/total-shareholder-returns/. 
The Board views this first quarterly dividend of 2026 to be prudent, having given due consideration to the Company’s capital allocation options 
and the Company’s overarching priority of maintaining a robust balance sheet under a range of market scenarios. Future dividend declarations 
will be subject to customary Board approval and consents.
2026 MANAGEMENT GUIDANCE
The Company’s full-year 2026 production will be generated solely by its deepwater Nigerian assets. The 2026 Management Guidance includes 
W.I. production guidance range of 23.0 – 28.0 kboepd and entitlement production range of 28.0 – 33.0 kboepd with approximately 68% 
expected to be light and medium crude oil and 32% conventional natural gas on a W.I. basis and 73% and 27% respectively on an entitlement 
basis. Meren is expected to sell 8 cargoes of approximately one million barrels each during 2026.
The table below summarizes the Company’s full-year 2026 Management Guidance. These estimates are based on a 2026 average Brent price 
of $63.0/bbl.
2026 Guidance 2025 Actuals
WI production (kboepd) (1) 23.0 – 28.0 30.8
Entitlement production (kboepd) (2) 28.0 – 33.0 35.1
EBITDAX ($ million) (3) 270.0 – 360.0 440.7
Cash flow from operations ($ million) (3) 185.0 – 255.0 261.8
Capital investments ($ million) 100.0 – 140.0 100.2
(1) Aggregate oil equivalent production data comprised of light and medium crude oil and conventional natural gas production net to the Company’s 
W.I. in Agbami, Akpo and Egina fields. These production rates only include sold gas volumes and not those volumes used for fuel, reinjected or flared. 
(2) Entitlement production is calculated using the economic interest methodology and includes cost recovery oil, royalty oil and profit oil and is different 
from working interest production that is calculated based on project volumes multiplied by the Company’s effective working interest in each license.
(3) This table includes non-GAAP measures that do not have a standardized meaning prescribed by IFRS Accounting Standards and, therefore, may not 
be comparable with the calculation of similar measures by other companies. The Company believes that the presentation of these non-GAAP figures 
provides useful information to investors and shareholders as the measures provide increased transparency. EBITDAX is a non-GAAP measure. This 
is used as a performance measure to understand the financial performance from the Company’s business operations without including the effects 
of the capital structure, tax rates, depreciation, depletion, amortization, impairment and exploration expenses.  Cash flow from operations before 
working capital and interest payments is a non-GAAP measure. This represents cash generated by removing the impact of working capital movements 
from cash generated by operating activities. It is a measure commonly used to better understand cash flow from operations across periods on a 
consistent basis, and when viewed in combination with the Company’s results provides a more complete understanding of the factors and trends 
affecting the Company’s performance.

===== SIDA 8 =====

Report to Shareholders  |  December 31, 2025
PAGE 8
THE COMPANY’S SHAREHOLDING AND 
WORKING INTERESTS
The Company’s material interests and material exploration partnership interests as at December 31, 2025, are summarized in the following 
table:
Meren’s Direct Working Interests (1)
Country Concession License renewal Working Interests
Nigeria
PML 52 and PPL 2003 (2) November 24, 2044
Meren
Chevron (Operator)
Famfa Oil
8%
32%
60% (carried)
PML 2, 3, 4 and PPL 261 – 
PSA (3) May 24, 2043
Meren
TotalEnergies (Operator)
SAPETRO
32%
48%
20% (carried)
South Africa Block 3B/4B October 26, 2024 (4)
Meren
TotalEnergies (Operator)
QatarEnergy
Azinam
Ricocure (Pty) Ltd
18% 
33%
24%
5.25%
19.75%
Equatorial Guinea
EG-18 March 1, 2027(5)
Meren (Operator)
GEPetrol
80%
20%
EG-31 February 29, 2028
Meren (Operator)
GEPetrol
80%
20%
Meren’s Shareholding in Impact (39.5%)
Country Concession License renewal Working Interests
Namibia
PEL 56 (Block 2913B) March 31, 2026 
Impact
TotalEnergies
QatarEnergy
NAMCOR
9.5% 
50.5%
30%
10% (carried)
PEL 91 (Block 2912) October 1, 2027
Impact
TotalEnergies
QatarEnergy
NAMCOR
9.5% 
47.2%
28.3% 
15% (carried)
(1) Net WI are subject to back-in rights or carried WI, if any, of the respective governments or national oil companies of the host governments. 
(2) Production currently from PML 52 and potential future production from PPL 2003 is covered by a PSA framework, in which Meren owns an 8% WI. 
(3) 50% of the production (currently from PMLs 2 and 3, future production from PML 4 and potential future production from PPL 261) is covered by a 
PSA framework, in which Meren owns a 32% WI. Meren’s net WI in these assets is therefore 16%.
(4) The operator has submitted an application for license renewal. This is currently awaiting Government approval.
(5) The Company has the option to extend the term of the first exploration sub-period of Block EG-18 by a further twelve months from March 1, 2027, 
to February 28, 2028 (inclusive), at its sole discretion. 
Information on the Company’s equity interests in Africa Energy and Impact is included in “Equity Investments in Associates” on page 19.

===== SIDA 9 =====

Report to Shareholders  |  December 31, 2025
PAGE 9
BUSINESS UPDATE
SHAREHOLDER RETURNS
During 2025, the Company distributed approximately $100.2 million and repurchased a total of 5,905,853 at an approximate cost of $8.3 
million for an aggregate return of $108.5 million for the year.
The Company’s shareholder returns policy consists of an annual base dividend of $100.0 million, supplemented by additional distributions, either 
through dividends or share buybacks, equivalent to up to 50% of free cash flow generated after payment of the base dividend, each of which 
remains subject to determination by the Board in its discretion and to a variety of factors and conditions existing from time to time. 
On this basis, and after payment of the $100 million base dividend, the Company did not generate additional free cash flow in 2025 available 
for further distributions and accordingly the aggregate return of $108.5 million represents the full extent of shareholder distributions for 2025. 
As detailed in the Highlights and Outlook section, the Company has declared the distribution of the Company’s first quarterly cash dividend in 
2026 of approximately $25.1 million or $0.0371 per share.
Notwithstanding the foregoing, the decision to declare any dividend or other shareholder distribution and the amount of future cash dividends 
declared and paid by Meren or shareholder distributions made by Meren, if any, will be subject to the discretion of the Board and may vary 
depending on a variety of factors and conditions existing from time to time. These may include, without limitation, business performance, 
operating environment where Meren’s assets are located, financial condition, growth plans, fluctuations in commodity prices, production levels, 
expected capital expenditure requirements, operating costs, royalties, foreign exchange rates, interest rates, compliance with any restrictions 
on the declaration and payment of dividends contained in any agreements to which Meren or any of its subsidiaries is a party from time to time 
(including, without limitation, financing agreements governing the RBL), and the satisfaction of liquidity and solvency tests imposed by the BC 
BCA for the declaration and payment of dividends. The actual amount, the record date and the payment date of any dividend are subject to the 
discretion of the Board. There can be no assurance that dividends will be paid at the current rate or at any rate in the future.
Pursuant to the Company’s current Normal Course Issuer Bid (“NCIB”) share repurchase program that was launched on December 8, 2025, 
Meren is authorized to repurchase through the facilities of the TSX, Nasdaq Stockholm and/or alternative Canadian trading systems, as and 
when considered advisable by Meren, up to 21,636,913 Common Shares of the Company for a total maximum amount of $35.0 million, which 
represented 5% of its “public float” of 432,738,277 Common Shares as at November 24, 2025. As of the same date, Meren had 675,725,593 
Common Shares issued and outstanding. 
Purchases of Common Shares may occur over a period of up to twelve months commencing December 8, 2025, and ending on the earlier of 
December 7, 2026, the date on which the Company has purchased the maximum number of Common Shares permitted under the NCIB, and 
the date on which the NCIB is terminated by Meren. There cannot be any assurances as to the number of Common Shares that will ultimately 
be acquired by the Company. Any Common Shares purchased by Meren under the NCIB will be cancelled.
GROUP OPERATIONS
On March 19, 2025, the Company completed the transaction with BTG Oil & Gas to consolidate its interest in Meren Coöperatief U.A. (previously 
known as Prime Oil & Gas Coöperatief U.A) (“Meren Coop”). The transaction was completed by way of amalgamation whereby BTG Oil & 
Gas exchanged its 50 percent interest in Meren Coop, held through its fully owned subsidiary BTG Pactual Holding S.à.r.l., in exchange for 
239,828,655 newly issued shares in the Company (the “amalgamation”). 
The production numbers included in the narrative discussion below include 100 percent of Meren Coop production numbers for all periods to 
have comparable production numbers for the purpose of this MD&A. 
PRODUCTION AND OPERATIONS
Production Metrics – rounded
Three months ended Years ended
Unit
December 31, 
2025
December 31, 
2024
December 31, 
2025
December 31, 
2024
Total gross field production boepd 207,400 270,300 241,900 273,600
Average daily WI production (1) boepd 28,100 34,400 30,800 34,000
Average daily entitlement production boepd 31,500 39,000 35,100 38,800
Oil volumes sold MMbbl 3.0 - 12.0 9.0
Gas volumes sold bcf 5.1 5.0 19.7 17.4
Oil/gas percentage split (2) % 67%/33% 74%/26% 71%/29% 77%/23%
(1) Production allocation occurs periodically and can result in a change in production numbers previously reported. 
(2) Calculated on a working interest basis.

===== SIDA 10 =====

Report to Shareholders  |  December 31, 2025
PAGE 10
BUSINESS UPDATE - CONTINUED
The total gross field production in Q4 2025 decreased compared to Q4 2024, primarily due to the planned turnaround maintenance (“TAM”) 
on the Agbami FPSO and, to a lesser extent, the expected natural reservoir decline across the portfolio together with the operational events 
described below. Throughout the quarter, production was actively managed in response to these challenges.
At Akpo and Egina, Q4 production was impacted by plant and compressor trips, including temporary shutdowns related to power supply 
issues, particularly during the second half of the quarter. These issues were actively managed through targeted operational interventions and 
maintenance activities, enabling operations and the fields to continue performing in line with expectations following resolution. 
In addition to the planned extensive turnaround maintenance on the Agbami FPSO, production was impacted by additional work on the Gas 
Turbine Compressors (“GTCs”) prior to and during the TAM exercise. The ramp-up following the full-field shutdown was further impacted by GTC 
start-up sequencing issues as well as planned work on the seawater injection system. The issues were addressed through focused repair and 
optimization efforts resulting in the gas compressors and the seawater injection pumps progressively brought back online by mid-January, two 
GTCs and one seawater injection pump were operational, with all GTCs fully online by mid-February. The maintenance and remediation work 
completed during the quarter is expected to support improved operational reliability and uptime going forward.
In Q4 2025, three oil liftings were allocated with a total sales volume of approximately 3.0 million barrels of oil at an average realized oil price 
of $64.4/bbl, compared to Dated Brent average of $63.7/bbl. In Q4 2024, no oil liftings were allocated. 
In 2025, a total of 12 oil liftings were allocated with a total sales volume of approximately 12.0 million barrels of oil at an average realized 
oil price of $72.2/bbl, compared to Dated Brent average of $69.1/bbl. In 2024, 9 oil liftings were allocated with a total sales volume of 
approximately 9.0 million barrels at an average realized oil price of $84.6/bbl.
FINANCIAL
Total net revenues, cost of sales, gross profit, opex/boe, tax and net debt numbers included in the narrative discussion below, on a constructed 
financial information basis, include 100 percent of Meren Coop numbers for all periods to have comparable numbers for the purpose of 
this MD&A and includes certain adjustments and reclassifications in the comparative periods to conform with Meren accounting policies and 
presentation in the Company’s  Consolidated Statement of Net Income or Loss and Other Comprehensive Income or Loss following completion 
of the amalgamation.
Cash flow from operations, free cash flow, capex and EBITDAX numbers included in the narrative discussion below have been reported for the 
year 2025 only on a constructed financial information basis. 
Constructed financial information (non-GAAP measure) to explain performance is included in the following tables to present on a consolidated 
basis, net income for 2025 and the cash flow statement for 2025, whereby the Meren Consolidated Statement of Net Income or Loss and Other 
Comprehensive Income or Loss and the Meren Consolidated Statement of Cash Flows for 2025 are combined with the Meren Coop Statement 
of Net Income and Comprehensive Income and the Meren Coop Statement of Cash Flows for the period until March 19, 2025. Adjustments 
included in the constructed financial information are to conform Meren Coop financial information with Meren accounting policies and for any 
transactions between Meren and Meren Coop prior to amalgamation for the purpose of presenting constructed financial information to explain 
performance.
The constructed financial information does not necessarily reflect what the combined company’s financial condition and results of operations 
would have been had the amalgamation occurred on January 1, 2025. Adjustments have been made to prepare the constructed financial 
information, which are based on certain assumptions. Both the adjustments and the assumptions made are described in the footnotes to the 
constructed financial information. The constructed financial information is presented for illustrative purposes only and are not necessarily 
indicative of: (i) the operating or financial results that would have occurred had the amalgamation actually occurred at the times contemplated 
by the constructed financial information; or (ii) the results expected in future periods. The constructed financial information are non-GAAP 
measures. Refer to more information on the non-GAAP measures provided on pages 11 - 17.

===== SIDA 11 =====

Report to Shareholders  |  December 31, 2025
PAGE 11
Constructed financial information for purposes of explaining performance
Condensed Consolidated Statement of Net Income/ (Loss)
(Expressed in millions of United States Dollars)
Year ended
Meren 2025 
per Financial 
Statements
Meren Coop 
for period from 
January 1, 2025, to 
March 19, 2025 Adjustments (1)
December 31, 
2025
Oil and gas sales 559.9 323.5 - 883.4
Net Revenue 559.9 323.5 - 883.4
Commodity risk management contracts 2.2 - - 2.2
Revenue 562.1 323.5 - 885.6
Cost of Sales 
Movements on overlift/underlift balances (46.3) (133.1) - (179.4)
Production costs (166.6) (54.3) 2.0 (218.9)
Depletion costs (207.9) (71.3) - (279.2)
Impairment charges (105.3) - - (105.3)
(526.1) (258.7) 2.0 (782.8)
Gross profit 36.0 64.8 2.0 102.8
General and administrative expenses (36.4) (6.2) - (42.6)
Operating (loss)/ profit (0.4) 58.6 2.0 60.2
Finance income 4.1 2.4 - 6.5
Finance expense (47.8) (21.3) - (69.1)
Net financial items (43.7) (18.9) - (62.6)
Share of profit from investment in joint venture 2.9 - (2.9) -
Share of loss from investments in associates (2.9) - - (2.9)
Reversal of impairment of investment in joint venture 55.9 - (55.9) -
Profit before tax 11.8 39.7 (56.8) (5.3)
Income tax (43.4) (34.0) - (77.4)
Net income/ (loss) attributable to common shareholders (31.6) 5.7 (56.8) (82.7)
(1) Adjustments to remove items related to Meren Coop as fully consolidated above.

===== SIDA 12 =====

Report to Shareholders  |  December 31, 2025
PAGE 12
BUSINESS UPDATE - CONTINUED
Condensed Consolidated Statement of Cash Flows
(Expressed in millions of United States Dollars)
Year ended
Meren 2025 
per Financial 
Statements
Meren Coop 
for period from 
January 1, 2025, to 
March 19, 2025 Adjustments (1)
December 31, 
2025
Cash flows generated by/ (used in):
Operations
Profit before tax 11.8 39.7 (56.8) (5.3)
Adjustments as per financial statements 166.8 41.5 58.8 267.1
Net cash generated in operating activities before working 
capital 178.6 81.2 2.0 261.8
Changes in working capital 94.0 (8.2) - 85.8
Net cash generated in operating activities 272.6 73.0 2.0 347.6
Investing
Investments in oil and gas properties and intangible 
exploration assets (75.6) (22.6) (2.0) (100.2)
Investments in other fixed assets (0.4) - - (0.4)
Distribution received from joint venture 60.0 - (60.0) -
Distribution received from associates 31.6 - - 31.6
Loan repaid by associated company 4.5 - - 4.5
Interest income received 4.2 2.2 - 6.4
Cash acquired from Meren Coop consolidation (2) 380.4 - (381.3) (0.9)
Net cash generated/ (used) in investing activities 404.7 (20.4) (443.3) (59.0)
Financing
Repayment RBL Facility (420.0) - - (420.0)
Repayment of principal portion of lease commitments (0.7) - - (0.7)
Dividends paid to shareholders (100.2) (120.0) 120.0 (100.2)
Repurchase of share capital (8.3) - - (8.3)
Interest expense paid (34.8) (10.8) - (45.6)
Net cash (used)/ generated in financing activities (564.0) (130.8) 120.0 (574.8)
Foreign exchange variation on cash and cash equivalents - - - -
Total cash flow 113.3 (78.2) (321.3) (286.2)
Cash and cash equivalents, beginning of the period 61.4 399.5 - 460.9
Cash and cash equivalents, end of the period 174.7 321.3 (321.3) 174.7
(1) Adjustments to remove items related to Meren Coop as Meren Coop fully consolidated above 
(2) Reflects impact of net cash movement on the level of BTG Pactual Holding S.à.r.l.

===== SIDA 13 =====

Report to Shareholders  |  December 31, 2025
PAGE 13
BUSINESS UPDATE - CONTINUED
Financial Metrics (1,2)
Three months ended Years ended
Unit
December 31, 
2025
December 31, 
2024
December 31, 
2025
December 31, 
2024
Total net revenues $’m 197.5 4.4 883.4 782.7
Cost of Sales (3) $’m 277.9 (67.4) 782.8 428.2
Gross profit $’m (78.2) 71.8 102.8 354.5
Opex/boe (4,5) $/boe 12.0 9.9 11.9 10.3
Cash flow from operations before working 
capital $’m 18.7 n/a 261.8 n/a
Cash flow from operations $’m 79.1 n/a 347.6 n/a
Free cash flow $’m 59.9 n/a 288.6 n/a
Free cash flow/boe (5) $/boe 20.7 n/a 22.5 n/a
Tax $’m (4.9) 44.2 77.4 120.5
Capex $’m 19.8 n/a 100.2 n/a
Net Debt $’m 155.3 289.1 155.3 289.1
EBITDAX $’m 72.7 n/a 440.7 n/a
Net Debt/EBITDAX ratio 0.4 n/a 0.4 n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on pages 14 - 17.
(2) Some of the figures presented in the table have been reported on a constructed basis. 
(3) Given the nature of the Company’s operations in terms of oil cargo liftings and the variability in their frequency from one quarter to next, the non-
cash accounting treatment of underlift/overlift and the timing between recording revenues and receipts of sales cash, leads to high variability in 
quarterly financial metrics. Please refer to the commentary in the rest of this section for the specific details of this period’s changes relative to the 
corresponding historical period.   
(4) Opex represents direct production costs.
(5) Boe is calculated on an entitlement basis. 
Total Net Revenues (1)
Three months ended Years ended
Unit
December 31, 
2025
December 31, 
2024
December 31, 
2025
December 31, 
2024
Oil revenue $’m 193.2 - 864.3 762.2
Gas revenue $’m 4.3 4.4 19.1 20.5
Total net revenue $’m 197.5 4.4 883.4 782.7
Realized oil prices (2) $/bbl 64.4 - 72.2 84.6
Oil volumes sold MMbbl 3.0 - 12.0 9.0
Realized gas prices $’m/bcf 0.8 1.0 1.0 1.2
Gas volumes sold Bcf 5.1 5.0 19.7 17.4
(1) Net revenues have been reported for the year 2025 and 2024 on a constructed financial information basis.
(2) Realized oil prices might be different to values calculated from the table above due to rounding.

===== SIDA 14 =====

Report to Shareholders  |  December 31, 2025
PAGE 14
BUSINESS UPDATE - CONTINUED
The increase in oil revenue in Q4 2025 was driven by 3 liftings in Q4 2025 compared to none in Q4 2024 as cargos that were initially scheduled 
for Q4 2024 were pushed into Q1 2025.
The increase in oil revenue in 2025 was mainly driven by higher liftings in 2025 despite a lower realized oil price of $72.2/bbl in 2025 compared 
to $84.6/bbl in 2024.
Cost of sales (1)
Three months ended Years ended
$’m
December 31, 
2025 
December 31, 
2024 
December 31, 
2025
December 31, 
2024
Depletion costs 52.9 87.0 279.2 372.0
Cost of operations 34.7 35.7 151.7 146.1
Movements on overlift/ underlift balances 63.4 (204.8) 179.4 (171.2)
Royalties – oil and gas 7.3 14.0 41.1 70.2
Others 14.3 0.7 26.1 11.1
Impairment charges 105.3 - 105.3 -
Total cost of sales 277.9 (67.4) 782.8 428.2
(1) Cost of sales has been reported for the year 2025 and 2024 on a constructed financial information basis.    
Cost of sales increased in Q4 2025 and 2025 compared to Q4 2024 and 2024 primarily due to anon-cash impairment recognized in relation 
to its oil and gas properties in the Agbami field CGU as a result of a combination of increased costs and lower oil prices, and cargos initially 
scheduled for Q4 2024 that were pushed into Q1 2025 resulting in a large overlift position in 2025 and a large underlift position in 2024 which 
is a credit to cost of sales. This increase in costs of sales was partly offset by lower depletion costs and lower royalties as a result of lower 
production volumes and lower oil prices.
As at December 31, 2025, the Company determined that there was an indicator of impairment in respect of its oil and gas properties related 
to the Agbami field CGU, reflecting a more conservative oil price and cost outlook compared to prior assumptions. This assessment was driven 
by recent oil price volatility and updated cost forecasts. A significant portion of the revised cost outlook relates to planned long-term life-
extension activities required to enable the Agbami FPSO to continue operating reliably and safely through the end of the current license period. 
These activities are also expected to enhance the flexibility of the Agbami FPSO to support future infill drilling and potential nearby tie-in 
opportunities, consistent with the Company’s long-term organic growth strategy. Such potential upside relates to contingent resources which 
are not included in the recoverable amount of the CGU for impairment testing purposes. The non-cash impairment does not reflect any adverse 
change in reservoir performance, reserves classification or the operational integrity of the Agbami field. The impairment resulted in a reduction 
in the deferred tax liability associated with oil and gas properties which has partially offset the impairment charge.
Other costs of sales mainly relate to the NDDC Levy, which concerns the Niger Delta Development Commission Levy imposed to fund the 
sustainable development of the Niger Delta region, the HCDF Levy, which concerns the Nigerian Content Development Fund and other costs 
incurred in Nigeria.
Opex/boe (1)
Opex/boe is a non-GAAP measure which represents production costs on a per barrel of oil equivalent basis (using entitlement production). This 
allows the Company to better analyze performance against prior periods on a comparable basis. The most direct financial statement measure is 
production costs. Entitlement production is calculated using the economic interest methodology and includes cost oil, profit oil and royalty oil 
and is different from WI production that is calculated based on project volumes multiplied by the effective WI in each Block.
Three months ended Years ended
Unit
December 31, 
2025
December 31, 
2024
December 31, 
2025
December 31, 
2024
Cost of operations $’m 34.7 35.7 151.7 146.1
Entitlement production MMboe 2.9 3.6 12.8 14.2
Opex/boe $/boe 12.0 9.9 11.9 10.3
(1) Cost of operations and entitlement production have been reported for the year 2025 and 2024 on a constructed financial information basis.
 
Opex/boe increased in Q4 2025 compared to Q4 2024 primarily from lower entitlement production and in 2025 compared to 2024 primarily 
from lower entitlement production and higher cost of operations. 
Entitlement production is used as the denominator as production costs include carry of costs that are recovered through entitlement production.
Cost of operations mainly relate to lifting costs from personnel, material and services from third parties.

===== SIDA 15 =====

Report to Shareholders  |  December 31, 2025
PAGE 15
BUSINESS UPDATE - CONTINUED
Cash flow from operations
Cash flow from operations before working capital is a non-GAAP measure. This represents cash generated by removing the impact from working 
capital from cash generated by operating activities and is a measure commonly used to better understand cash flow from operations across 
periods on a consistent basis and when viewed in combination with the Company’s results provides a more complete understanding of the 
factors and trends affecting the Company’s performance. A reconciliation from cash flow from operations to cash flow from operations before 
working capital is shown below:
Three months ended Years ended
$’m
December 31, 
2025 
December 31, 
2024 (1)
December 31, 
2025 (1)
December 31, 
2024 (1)
Cash flow from operations 79.1 n/a 347.6 n/a
Working capital adjustments included in cash flow from 
operations (60.4) n/a (85.8) n/a
Cash flow from operations before working capital 18.7 n/a 261.8 n/a
(1) Cash flow from operations has been reported for the year 2025 only on a constructed financial information basis. 
Free cash flow and Free cash flow/boe
Free cash flow is a non-GAAP measure. This measure represents cash generated after costs, and is a measure commonly used to assess the 
Company’s profitability. 
Free cash flow/boe is a non-GAAP ratio which represents free cash flow on a per barrel of oil equivalent basis using entitlement production 
which allows the Company to better analyze performance against prior periods on a comparable basis. Entitlement production is calculated 
using the economic interest methodology and includes cost oil, profit oil and royalty oil and is different from WI production that is calculated 
based on project volumes multiplied by the effective WI in each Block.  
A reconciliation from total cash flow (a GAAP measure) to free cash flow (a non-GAAP measure) is shown below:
Three months ended Years ended
Unit
December 31, 
2025 
December 31, 
2024 (1)
December 31, 
2025 (1)
December 31, 
2024 (1)
Total cash flow $’m (2.0) n/a (286.2) n/a
Add back dividends paid to shareholders $’m 25.0 n/a 100.2 n/a
Add back repurchase of share capital $’m - n/a 8.3 n/a
Add back debt service costs (2) $’m 36.9 n/a 466.3 n/a
Free cash flow $’m 59.9 n/a 288.6 n/a
Entitlement production MMboe 2.9 n/a 12.8 n/a
Free cash flow/boe $/boe 20.7 n/a 22.5 n/a
(1) Free cash flow and Free cash flow/boe have been reported for the year 2025 only on a constructed financial information basis.  
(2) Debt service costs comprise interest payments, repayments and drawdowns of third-party borrowings.

===== SIDA 16 =====

Report to Shareholders  |  December 31, 2025
PAGE 16
BUSINESS UPDATE - CONTINUED
Tax
The tax expense is made up of the following items:
Three months ended Years ended
$’m
December 31, 
2025
December 31, 
2024 (1)
December 31, 
2025 (1)
December 31, 
2024 (1)
Deferred income tax (60.3) (24.5) (106.2) (80.9)
Education tax 5.1 2.1 15.6 14.2
Corporate income tax 36.0 17.1 129.2 130.1
Withholding tax on dividends 12.0 15.0 36.5 22.5
Capital gains tax - 33.0 - 33.0
Petroleum Profit Tax - - - (2.3)
Other taxes 2.3 1.5 2.3 3.9
Total tax (4.9) 44.2 77.4 120.5
(1) Tax has been reported for the year 2025 only on a constructed financial information basis.
In Q4 2025, there was a tax credit. This is from a release of the deferred tax liability as a result of the non-cash impairment recognized to the 
Agbami CGU.
Education tax is imposed on every Nigerian company at a rate of 3.0% of the assessable profit in the period.   
Corporate income tax is imposed at a rate of 30.0% of the assessable profits in Nigeria in the period. 
Petroleum Profit Tax is a tax on the income of companies engaged in upstream petroleum operations in Nigeria. Since operating under the new 
PIA terms following conversion during 2023, the leases and licenses are no longer subject to PPT.
Other taxes relates to the Naseni (National Agency for Science and Engineering Infrastructure) Levy that is imposed in Nigeria based on 0.25% 
of profits before tax and the Police Fund Levy that is imposed in Nigeria based on 0.005% of net profit.
From January 1, 2026, a new 4% Development Levy on assessable profits is being introduced which will replace Education tax and the Naseni 
Levy. 
Capital expenditure
Capital expenditure is made up of the following items:
Three months ended Years ended
$’m
December 31, 
2025
December 31, 
2024 (1)
December 31, 
2025 (1)
December 31, 
2024 (1)
Nigeria 17.3 n/a 93.8 n/a
Equatorial Guinea 2.8 n/a 6.6 n/a
South Africa (0.3) n/a (0.2) n/a
Total capex 19.8 n/a 100.2 n/a
(1) Capital expenditure has been reported for the year 2025 only on a constructed financial information basis.  
 
Capital expenditure in Q4 2025 and 2025 in Nigeria mainly related to planned infill drilling on Egina and Akpo plus facilities costs on Agbami.  
Net Debt
Net Debt is a non-GAAP measure. Net Debt is calculated as loans and borrowings less cash and cash equivalents.
Years ended
As at/ $’m
December 31, 
2025
December 31, 
2024
Loans and borrowings 330.0 750.0
Cash and cash equivalents (174.7) (460.9)
Net Debt 155.3 289.1
 
As at December 31, 2025, the Company has $174.7 million of cash and cash equivalents and $330.0 million of debt (as at December 31, 2024 
- $460.9 million of cash and cash equivalents and $750.0 million of debt). During 2025, the Company repaid $420.0 million under its RBL facility 
reducing outstanding debt to $330.0 million. RBL facility headroom of $138.4 million at the end of 2025.

===== SIDA 17 =====

Report to Shareholders  |  December 31, 2025
PAGE 17
BUSINESS UPDATE - CONTINUED
EBITDAX and Net Debt/EBITDAX
EBITDAX is a non-GAAP measure. This is used as a performance measure to understand the financial performance from the Company’s business 
operations without including the effects of the capital structure, tax rates, DD&A, impairment expenses, unrealized results on commodity risk 
management contracts and by adding back realized results on commodity risk management contracts. A reconciliation from total profit (a GAAP 
measure) to EBITDAX (a non-GAAP measure) is shown below.
Net Debt/EBITDAX is a non-GAAP measure. Net Debt divided by EBITDAX is a measure of leverage.
Three months ended Years ended
$’m
December 31, 
2025
December 31, 
2024
December 31, 
2025 (1)
December 31, 
2024
Total profit/ (loss) (90.8) n/a (82.7) n/a
Add back:
Tax (4.9) n/a 77.4 n/a
Finance costs 12.5 n/a 69.1 n/a
Finance income (0.5) n/a (6.5) n/a
Impairment charges 105.3 n/a 105.3 n/a
Depletion, depreciation and amortization costs 53.3 n/a 280.3 n/a
Commodity risk management contracts (2.2) n/a (2.2) n/a
EBITDAX 72.7 n/a 440.7 n/a
Net Debt 155.3 n/a
Net Debt/EBITDAX 0.4 n/a
(1) EBITDAX and Net Debt/EBITDAX have been reported for the year 2025 only on a constructed financial information basis. 
Crude Oil Marketing
In considering cargo liftings, the reader should note that the timing and the frequency of these can vary based on a number of factors such 
as reservoir performance; actual realized oil price; capex; opex; underlift/overlift positions and marine logistics. The revenue numbers reported 
include cost oil, profit oil and royalty oil where relevant for each field.
In most of the Group’s oil offtake contracts, the Dated Brent component of the forward price at the time of entering the contract is not fixed 
but determined on or around the date of the lifting for spot cargos either on an average monthly basis, 5-days after bill of lading date or similar 
pricing mechanism. The average cargo size lifted is one million barrels of oil. 
Oil sales were comprised of the following: 
Three months ended Years ended
Oil Sales Unit
December 31, 
2025
December 31, 
2024
December 31, 
2025 (1)
December 31, 
2024 (1)
Gross crude oil sales
Quantity in Mboe Mboe 3,002.3 - 11,965.5 9,012.8
Average sales price $/bbl 64.4 - 72.2 84.6
Average Bloomberg Dated Brent for the period $/bbl 63.7 - 69.1 82.7
(1) Oil sales have been reported for the year 2025 and 2024 on a constructed financial information basis.
 
The Company sold 3 cargoes during Q4 2025 at a price of $64.4/bbl.

===== SIDA 18 =====

Report to Shareholders  |  December 31, 2025
PAGE 18
BUSINESS UPDATE - CONTINUED
Hedging
The Group’s cash flow is exposed to fluctuations in the oil price. A decrease in oil price will lead to a reduction in oil revenue, and vice versa, but 
this is offset by an opposite movement in sales entitlement, royalties and taxes. The post-tax net entitlement production represents sales that 
the Group has physical price exposure. 
The Group uses a mix of financial derivatives and physical forward sales contracts to manage its commodity price risk and ensure stability in 
cash flows. Its strategy is to hedge between 70-100% of its post-tax net entitlement production for the next 12-months. As of December 31, 
2025, the group has a mix of physical and financial hedges, as per the table below. 
H1 2026 breakdown Mbbl
Fixed price 
$/bbl
Sold put 
$/bbl
Bought put 
$/bbl
Sold call 
$/bbl
Sold swap 
$/bbl
Collar 300 - - 60.00 67.15 -
Fixed Price (Offtake) 2,000 62.09 - - - -
Total 2,300
H2 2026 breakdown Mbbl
Fixed price 
$/bbl
Sold put 
$/bbl
Bought put 
$/bbl
Sold call 
$/bbl
Sold swap 
$/bbl
Swap 900 - - - - 63.95
Three way put spread 450 - 45.00 60.00 65.78 -
Collar 300 - - 60.00 74.00 -
Total 1,350
Other non-GAAP measures 
This MD&A includes non-GAAP measures, non-GAAP ratios and supplementary financial measures as further described herein. These non-
GAAP figures do not have a standardized meaning prescribed by IFRS Accounting Standards and, therefore, may not be comparable with the 
calculation of similar measures by other companies. The Company believes that the presentation of these non-GAAP figures provides useful 
information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance 
against prior periods on a comparable basis.
NIGERIA
Following the amalgamation, the Company has direct interests in three producing fields, three undeveloped discoveries, and number of near-
field exploration opportunities in deepwater Nigeria through four PMLs and two PPLs.
The three producing fields are Akpo (PML 2), Egina (PML 3) and Agbami (PML 52). The primary undeveloped oil discovery is Preowei (PML 4), 
which lies to the north of Egina and Akpo fields and is planned to be developed through a subsea tie-back development to the Egina FPSO. 
The other two undeveloped discoveries are Egina South (PPL 261), which lies to the southwest of Egina and Akpo fields, and the Ikija discovery 
(PPL 2003), which lies to the west of Agbami. The Company’s assets are located in the deepwater area of the Niger Delta more than 100 km 
offshore Nigeria. 
Please refer to pages 17 - 18 of the Company’s Annual Information Form (“AIF”) for the Year Ended December 31, 2025, for the detailed 
commercial information, and pages 39 - 48 of the same document for the detailed technical information on these assets. The AIF is available on 
SEDAR+ at www.sedarplus.ca or on the Company’s website at www.mereninc.com.  
BLOCK 3B/4B – SOUTH AFRICA 
Meren, through a wholly-owned subsidiary, holds an 18.0% interest in Block 3B/4B, which lies in the Orange Basin. The Block 3B/4B legislative 
notification and appeals process is currently suspended pending a Supreme Court of Appeal judgment in respect of Block 5/6/7. The operator 
of Block 3B/4B currently plans to drill the first exploration well as soon as the Environmental Authorization is confirmed.
Please refer to the Company’s AIF for the year-ended December 31, 2025, for further details on Block 3B/4B.
BLOCKS EG-18 AND EG-31 – EQUATORIAL GUINEA 
The Company, through wholly-owned subsidiaries, holds an operated WI of 80.0% in each of Blocks EG-18 and EG-31, offshore Equatorial Guinea.
On December 17, 2025, the Company received notification from the Ministry of Hydrocarbons and Mining Development in Equatorial Guinea 
approving extensions of up to two years to the first exploration sub period on each block.
During Q4 2025 the Company continued dialogue with potential partners during its active data room process across both blocks and progressed 
discussions with the government and GEPetrol on forward plans with the aim of forming joint ventures capable of planning exploration drilling 
as early as late 2026 or 2027.
Please refer to the Company’s AIF for the year-ended December 31, 2025, for further details on Blocks EG-18 and EG-31.

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Report to Shareholders  |  December 31, 2025
PAGE 19
BUSINESS UPDATE - CONTINUED
EQUITY INVESTMENTS IN ASSOCIATES
As at December 31, 2025, the Company held equity investments in two oil and gas companies, which provides exposure to several high-impact 
exploration drilling prospects in South Africa and Namibia. 
The Company held the following equity investments in associates as of December 31, 2025:
Africa Energy Impact (1)
Issued and Outstanding 479,162,450 1,139,147,442
Shares held by Meren at December 31, 2024 55,396,483 449,464,396
Shares acquired in the period - -
Shares held by Meren at December 31, 2025 55,396,483 449,464,396
Meren’s holding (%) – December 31, 2025 11.56% 39.46%
Meren’s holding (%) – December 31 2024 19.67% 39.46%
Share price (CAD) on December 31, 2025 0.11 -
Exchange rate to USD on December 31, 2025 0.73 -
(1) Impact is a privately held UK company and no share price is available.
Impact
Impact is a private UK oil and gas exploration company with assets located offshore Namibia and South Africa. Please refer to the Company’s 
AIF for the year-ended December 31, 2025, for further details on the Company’s shareholding in Impact and the supplementary technical and 
commercial information.
The Company through its 39.5% shareholding in Impact Oil & Gas Limited has an effective 3.8% interest in Blocks 2912 and 2913B, offshore 
Namibia, with the latter block containing the Venus light oil discovery. The blocks are operated by a subsidiary of TotalEnergies. Under Impact’s 
carried-interest arrangement with TotalEnergies, Meren’s exposure to all development and exploration costs on Blocks 2912 and 2913B 
remains fully funded through to first commercial production, without any financial cap. 
ENVIRONMENTAL, SOCIAL AND GOVERNANCE 
Following the amalgamation, the Company reiterates its commitment to be a responsible owner and operator, integrating sustainability 
considerations throughout its decision-making processes to support Company commercial objectives.
During 2025 there were no reported material HSEC incidents.
GHG emissions during the reporting period were in line with operational forecasts. Further details will be set out in the Company’s annual 
Sustainability Report.
Activities continue on the Company’s development assets with no material developments to be reported during the reporting period. The Block 
3B/4B legislative notification and appeals process is currently suspended pending a Supreme Court of Appeal judgment in respect of Block 
5/6/7.
The Company’s 2024 Sustainability Report, published on May 12, 2025, is disclosed on the Company website, as with previous reports it contains 
more detailed information on the Company’s performance and strategy related to sustainability matters.  The Company’s 2025 Sustainability 
Report will be published on the Company’s website during the first half of 2026.

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Report to Shareholders  |  December 31, 2025
PAGE 20
SELECTED ANNUAL INFORMATION
For the years ended
December 31, 
2025
December 31, 
2024
December 31, 
2023
Statement of Net Income or Loss and Other Comprehensive Income or Loss:
Revenue 562.1 - -
Net (loss)/ income attributable to common shareholders ($’m) (31.6) (279.1) 87.1
Data per Common Share:
Basic income/(loss) per share ($/share) (0.05) (0.62) 0.19
Diluted income/(loss) per share ($/share) (0.05) (0.62) 0.18
Balance Sheet:
Financial liabilities ($’m) 333.8 3.3 -
Total assets ($’m) 1,951.9 615.2 966.2
Cash dividends (per share basis) 0.1484 0.05 0.05
In 2025, the Company recorded revenue, mainly related to oil sales, following the amalgamation with Meren Coop. In 2024 and 2023, the 
Company held a 50% investment in Meren Coop, accounted for as a Joint Venture and therefore no revenue was recognized in these years. 
In 2025, the Company recorded a net loss attributable to common shareholders of $31.6 million and a net loss of $279.1 million in 2024. 
In 2025, the Company fully consolidated Meren Coop and partly reversed impairment on its investment in joint venture when the Company 
completed the transaction with BTG Oil & Gas to consolidate its interest in Meren Coop on March 19, 2025, and the loss was primarily from 
anon-cash impairment of $105.3 million to the Agbami CGU. In 2024, the Company recorded a net loss attributable to common shareholders of 
$279.1 million which is a decrease from the net income of $87.1 million recorded in 2023. In 2024, this was primarily made up of income from 
the Company’s investment in Meren Coop of $226.0 million offset against losses from the Company’s investment in associates of $38.7 million 
and an impairment in the Company’s investment in Meren Coop of $436.7 million as the fair value of the Company’s existing shareholding in 
Meren Coop was calculated based on the implied value of the Proposed Reorganization, which was in excess of the carrying value resulting in a 
non-cash impairment loss on the investment in Meren Coop. 
In 2025, the basic and diluted loss per share was $0.05 (2024 – basic and diluted loss per share of $0.62). The loss per share in 2025 has arisen 
from a non-cash impairment recognized to oil and gas properties related to the Agbami CGU. In 2024, the basic and diluted loss per share was 
$0.62 (2023 – the basic income per share was $0.19 and the diluted income per share was $0.18). The loss per share has arisen primarily from 
the impairment recognized to the Company’s investment in Meren Coop. 
In 2025, the increase to financial liabilities is mainly from the RBL facility held by Meren Coop, which is now consolidated in the Group’s balance 
sheet. In 2024, the increase to financial liabilities related to a lease liability recognized for lease of an office building. 
In 2025, total assets have increased following the amalgamation and recognition of oil and gas interests in the Groups operations in Nigeria. In 
2024 the decrease in total assets is primarily due to the decrease in cash balances and the decrease to the Company’s investment in Meren 
Coop from the impairment recognized.

===== SIDA 21 =====

Report to Shareholders  |  December 31, 2025
PAGE 21
SUMMARY OF QUARTERLY INFORMATION
All financial information included in the narrative discussion below is based on the Consolidated Statement of Net Income or Loss and Other 
Comprehensive Income or Loss and considers the amalgamation closing on March 19, 2025. 
Summarized quarterly results for the past eight quarters are as follows:
For the three months ended
31-Dec 
2025
30-Sep 
2025
30-Jun 
2025
31-Mar 
2025
31-Dec 
2024
30-Sep 
2024
30-Jun 
2024
31-Mar 
2024
Revenue 199.7 216.7 69.3 76.4 - - - -
Net (loss)/ income attributable to 
common shareholders ($’m) (90.8) 5.2 3.1 50.9 6.2 (289.2) 0.4 3.5
Weighted average shares – Basic ‘000 675,686 675,513 675,012 468,472 442,690 442,960 451,231 460,991
Weighted average shares – Diluted 
‘000 675,686 682,770 682,039 476,836 449,667 442,960 464,890 474,746
Basic (loss)/ income per share ($) (0.13) 0.01 0.00 0.11 0.02 (0.65) 0.00 0.01
Diluted (loss)/ income per share ($) (0.13) 0.01 0.00 0.11 0.02 (0.65) 0.00 0.01
 
SUMMARY OF KEY ITEMS OF FINANCIAL PERFORMANCE IN THE YEARS ENDED DECEMBER 31, 2025, AND 
DECEMBER 31, 2024
Three months ended Years ended
December 31,  
2025 
December 31,  
2024
December 31,  
2025 
December 31,  
2024
Revenue 199.7 - 562.1 -
Gross (loss)/ profit (78.2) - 36.0 -
General and administrative expenses (5.0) (13.3) (36.4) (32.4)
Net (loss)/ income (90.8) 6.2 (31.6) (279.1)
 
Revenue
Revenue generated in Q4 2025 and 2025 was $199.7 million and $562.1 million respectively (Q4 2024 and 2024 – nil) and primarily related 
to 3 cargoes sold in Q4 2025 at an average price of $64.4/bbl and 5 additional cargoes sold in the period post amalgamation to the end of Q3 
2025 at an average price of $70.4/bbl. Prior to the closing of the amalgamation on March 19, 2025, the Company did not report any revenue 
in its Consolidated Statement of Net Income or Loss and Other Comprehensive Income or Loss.
Gross profit
Gross loss reported in Q4 2025 and gross profit in 2025 was $78.2 million and $36.0 million respectively (Q4 2024 and 2024 – nil). Gross profit 
was impacted by costs of sales in Q4 2025 and 2025 of $277.9 million and $526.1 million respectively (Q4 2024 and 2024 – nil) and mainly 
comprised of non-cash impairment charges of $105.3 million to oil and gas properties related to the Agbami CGU, depletion costs of $52.9 
million and $207.9 million respectively, net overlift movements of $63.4 million and $46.3 million respectively, and costs of operations of $34.7 
million and $114.3 million respectively.

===== SIDA 22 =====

Report to Shareholders  |  December 31, 2025
PAGE 22
General and administrative costs 
On March 19, 2025, the Company announced the completion of the amalgamation to acquire the remaining 50% interest in Meren Coop in 
exchange for 239,828,655 newly issued common shares in Meren. This transaction falls under IFRS 3 under which acquisition related costs are 
expensed in the periods in which the costs are incurred, and the services are received. 
The table below shows adjusted general and administrative expenses, which is a non-GAAP measure, by excluding the BTG Oil & Gas transaction 
related expenses and is meant to improve comparability between periods. The BTG Oil & Gas transaction related expenses also include certain 
LTIP charges for fully vested LTIP units as a result of the closing of the amalgamation.
Three months ended Years ended
December 31,  
2025 
December 31,  
2024
December 31,  
2025 
December 31,  
2024
General and administrative expenses 5.0 13.3 36.4 32.4
BTG Oil & Gas transaction related expenses - (0.7) (9.0) (6.9)
Adjusted general and administrative expenses 5.0 12.6 27.4 25.5
 
Adjusted general and administrative expenses, including share-based compensation charges relating to the LTIP and Stock Option Plan that are 
not impacted by the closing of the amalgamation, in Q4 2025 and 2025 amounted to $5.0 million and $27.4 million respectively (Q4 2024 and 
2024 - $12.6 million and $25.5 million respectively). Share-based compensation charges not impacted by the closing of the amalgamation in 
Q4 2025 and 2025 amounted to $1.4 million and $3.7 million respectively (Q4 2024 and 2025 – $0.2 million and $1.5 million respectively) are 
impacted by movements in the share price of the Company and performance conditions.
Adjusted general and administrative expenses excluding share-based compensation charges amounted to $3.6 million in Q4 2025 compared 
to $12.4 million in Q4 2024. The decrease is mainly driven by cost allocations since closing of the amalgamation with these cost allocations 
reflected in Q4 2025.
Adjusted general and administrative expenses excluding share-based compensation charges amounted to $23.7 million in 2025, which is in line 
with 2024 amounting to $24.0 million. 
SUMMARY OF KEY ITEMS OF FINANCIAL POSITION AS AT DECEMBER 31, 2025, AND DECEMBER 31, 2024
As at
December 31,  
2025
December 31,  
2024
Assets 
Oil and gas properties 1,413.5 -
Intangible exploration assets 43.7 29.3
Equity investments in associates 142.2 177.6
Cash and cash equivalents 174.4 61.4
Outstanding bank debt 330.0 -
Oil and gas properties
Oil and gas properties have increased following closing of the amalgamation to acquire the remaining 50% interest in Meren Coop following 
which Meren Coop is fully consolidated by the Company.
As at December 31, 2025, oil and gas properties amounted to $1,413.5 million (as at December 31, 2024 – nil) and related to the licenses PML 
52 (covering part of the Agbami field), PML 2 (Akpo field), PML 3 (Egina field) and PML 4 (Preowei Field) in Nigeria. 
Intangible exploration assets:
As at December 31, 2025, the carrying amount of the Company’s intangible exploration assets in Equatorial Guinea was $24.5 million (as at 
December 31, 2024 – $17.9 million) and related to its 80% interest in Blocks EG-18 and EG-31. 
As at December 31, 2025, the carrying amount of the Company’s intangible exploration assets in South Africa was $19.2 million (as at 
December 31, 2024 - $11.4 million) and related to its 18.0% (as at December 31, 2024 – 17.0%) participating interest in the Block 3B/4B 
Exploration Right.
Equity investments in associates
As at December 31, 2025, the Company’s investment in associates was $142.2 million compared to an investment value of $177.6 million 
as at December 31, 2024. The carrying value of the investments decreased by $35.4 million in 2025 mainly from the Company’s share of 
the associates losses of $2.9 million in combination with a distribution by Impact of $31.6 million net to the Company’s shareholding. The 
investment in Impact, holding the working interests in the Namibia Orange Basin Blocks 2913B and 2912, makes up $140.7 million of the total 
equity investments in associates. 
SUMMARY OF QUARTERLY INFORMATION - CONTINUED

===== SIDA 23 =====

Report to Shareholders  |  December 31, 2025
PAGE 23
Cash and cash equivalents
Cash and cash equivalents have increased following closing of the amalgamation to acquire the remaining 50% interest in Meren Coop following 
which Meren Coop is fully consolidated by the Company. As at December 31, 2025, the Company had $174.7 million cash and cash equivalents 
on hand, compared to a cash balance of $61.4 million as at December 31, 2024. The Company acquired cash balances on closing date of the 
amalgamation of $380.4 million, the Company received a distribution from Meren Coop of $60.0 million prior to the closing of the amalgamation, 
repaid $420.0 million of the RBL facility, returned $108.5 million to shareholders by way of dividends and share buybacks, received a distribution 
from Impact of $31.6 million, incurred capital and operational expenditure in respect of the licenses in Nigeria, Equatorial Guinea and South 
Africa, settled working capital balances and incurred general and administrative costs. 
Outstanding bank debt
Outstanding bank debt increased following closing of the amalgamation to acquire the remaining 50% interest in Meren Coop following which 
Meren Coop is fully consolidated by the Company. Subsequent to closing of the amalgamation, the Company cancelled its corporate facility, 
repaid $420.0 million under the RBL facility, reducing outstanding bank debt to $330.0 million as at December 31, 2025. RBL facility headroom 
of $138.4 million at the end of 2025.
LIQUIDITY AND CAPITAL RESOURCES 
As at December 31, 2025, the Company had cash balances of $174.7 million and net working capital balances (including cash balances) of $18.9 
million negative. Net working capital is calculated as current assets less current liabilities as presented in the consolidated balance sheet as per 
December 31, 2025. The Company’s primary source of liquidity is operating income in Nigeria and the remaining undrawn amounts on the RBL. 
Reserves Based Lending Facility
Meren has a Reserves Based Lending Facility (“RBL”) in place with $800.0 million in commitments from the date of the amalgamation. The total 
amount that can be drawn under the RBL is limited to the Borrowing Base Amount (“BBA”), which is subject to redeterminations on March 31 
and September 30 of each year, limited by aggregate commitments. As of December 31, 2025, the BBA was $468.4 million, which will amortize 
as the RBL moves towards final maturity. On October 28, 2025, the Company voluntarily cancelled $100.0 million of its RBL commitments 
resulting in a remaining total commitment of $700.0 million.
The principal bore interest at Term SOFR + 4.00% until June 2025 and bears interest of Term SOFR + 4.25% until June 2027, then Term SOFR 
+ 4.50% until final maturity on June 20, 2029. In addition, commitment fees of 40% of the margin are payable on the undrawn but available 
portion of the RBL, and commitment fees of 20% of the margin are payable on the unavailable portion of the RBL. 
The RBL perimeter remains at the Meren Coop level – Meren Coop is the borrower, and Meren 52 and Meren 234 are the guarantors. The main 
security package is comprised of security over the shares, production assets, contracts and rights of the Nigerian entities - Meren 52 and Meren 
234. In addition, RBL lenders have security over cash and cash equivalents held in project accounts, receivables against cargos sold and all 
relevant insurance policies of the three entities. 
All financial and liquidity covenants covered by the RBL are restricted to these three entities. The  entities shall ensure that total net debt to 
adjusted EBITDAX on each quarter is no greater than 3.0:1, that the historic debt service cover ratio for the preceding year is greater than 
1.20:1, and that on each quarter of each year during each of the four successive quarters there are or will be sufficient funds available to the 
group to meet all relevant expenditure to be incurred in each of these four successive quarters as they fall due. The Company has been in 
compliance with the covenants in the three months ended December 31, 2025.
Material contractual commitments
In accordance with the terms of the production sharing contracts entered into by the Group along with other partners in respect of its oil 
fields and blocks, the Group has certain minimum exploration and development commitments with estimated capital expenditures in oil and gas 
properties of $0.3 billion as at December 31, 2025, $0.2 billion as at December 31, 2026, $0.1 billion as at December 31, 2027 and $0.1 billion 
as at December 31, 2028.
Future Funding Outlook
To finance its future acquisition, exploration, development and operating costs, the Company may require financing from external sources, 
including issuance of new shares, issuance of debt or executing farmout or disposition arrangements. There can be no assurance that such 
financing will be available to the Company or, if available, that it will be offered on terms acceptable to the Company.
The Company believes that its existing cash balances combined with anticipated funds flow from its operations and undrawn facilities will 
provide sufficient liquidity for the Company to meet its financing, operating and capex commitments as they fall due.

===== SIDA 24 =====

Report to Shareholders  |  December 31, 2025
PAGE 24
OUTSTANDING SHARE DATA
The following table outlines the maximum potential impact of share dilution upon full execution of outstanding convertible instruments as at 
the effective date of the MD&A.
Common shares outstanding 675,909,193
Outstanding share purchase options 22,616
Outstanding restricted share units 1,368,733
Outstanding performance share units 10,992,194
Full dilution impact on Common Shares outstanding 688,292,736
 
RELATED PARTY TRANSACTIONS
Transactions with Africa Energy:
On December 19, 2022, Africa Energy announced that it had secured a $5.0 million promissory note of which $2.0 million was provided by the 
Company and the remaining by other parties. On November 7, 2023, the promissory note provided by the Company and other parties to Africa 
Energy was increased by $3.3 million with $1.5 million of the increase provided by the Company by the end of the year ended December 31, 
2024. No funds were provided during 2025, and $0.8 million was provided in the year ended December 31, 2024. The note was unsecured and 
matured on March 31, 2025, when the principal and accrued interest was repaid by Africa Energy in full. The note carried an annual interest 
rate of 15%. In the three months ended March 31, 2025, interest on the note amounted to $0.2 million (year ended December 31, 2024 - $0.5 
million).
Transactions with Eco:
On July 26, 2024, the Company signed an agreement with Eco to acquire an additional 1.0% interest in Block 3B/4B from Azinam, in exchange 
for all common shares and warrants over common shares held by the Company in Eco. On January 13, 2025, the Company announced that 
it had completed this transaction. The Company’s interest in Block 3B/4B increased by 1.0% to 18.0% and the Company ceased to be a 
shareholder in Eco. Meren will benefit from the carry agreed between Eco, TotalEnergies and QatarEnergy for this incremental interest.   
Transactions with Impact:
On January 29, 2025, Impact distributed $31.6 million net to the Company’s shareholding.
Transactions with BTG Oil & Gas:
The Company has recorded an indemnity asset of $21.6 million recognized under the deed of indemnity entered into between the Company 
and BTG Oil & Gas (see note 14).  
Remuneration of Directors and Senior Management:
Remuneration of Non-Executive Directors and Senior Management includes all amounts earned and awarded to the Company’s Board of 
Directors and Senior Management. Senior Management includes the Company’s President and Chief Executive Officer, Chief Financial Officer, 
Chief Commercial and Operations Officer, Chief Operating Officer (position removed in 2025), Chief Technical Officer (position removed in 
2025), Chief Legal Officer and Chief Human Resources Officer. 
Directors’ fees include Board and Committee Chair retainers. Management’s short-term wages and benefits include salary, benefits, bonuses and 
any other cash-based compensation earned or awarded during the year. Share-based compensation includes expenses related to the Company’s 
share purchase option plan as well as the Long-Term Incentive Plan.
For the years ended
December 31,  
2025
December 31,  
2024
Non-Executive Directors' fees 0.7 0.5
Non-Executive Directors' share-based compensation 1.4 0.6
Managements’ short-term wages and benefits 7.1 7.3
Managements’ share-based compensation 3.5 0.5
12.7 8.9

===== SIDA 25 =====

Report to Shareholders  |  December 31, 2025
PAGE 25
COMMITMENTS AND CONTINGENCIES
The following commitments and contingencies are representative of the Company’s net obligations at the effective date of the MD&A.
MEREN COÖPERATIEF U.A:
Under the Meren Coop Sale and Purchase Agreement completed on January 14, 2020, a deferred payment of $118.0 million, subject to 
adjustment, may be due to the seller contingent upon the timing of the final PML 52 tract participation in the Agbami field. The signing 
of the Securitization Agreement by Meren Coop in 2021 led to the Company reassessing its view of the likelihood of making a contingent 
consideration payment to the seller. The signing of the Securitization Agreement by Meren Coop does not constitute a redetermination of the 
tract participation and therefore does not trigger the payment of a contingent consideration under the Sale and Purchase Agreement but, at 
the Company’s discretion, could trigger discussions with the seller. The outcome of this process is uncertain. In 2021, the Company recorded 
$32.0 million as contingent consideration and increased this to $40.4 million as at December 31, 2024, and to $43.4 million in the year ended 
December 31, 2025.
On June 25, 2021, Meren Nigeria 52 Limited (previously named Prime 127 Nigeria Limited) (“Meren 52”), a subsidiary of Meren Coop, signed a 
securitization agreement with two of the unit parties, Equinor and Chevron (the “Securitization Agreement”), whereby Equinor agreed to pay 
a security deposit to the two other JV parties to secure future payments due under that Securitization Agreement, pending a comprehensive 
resolution being reached among all unit parties in respect of the tract participation in the Agbami field by December 27, 2024. In accordance 
with the Securitization Agreement, on June 29, 2021, Meren 52 received from Equinor its portion of the security deposit in the form of a cash 
payment of $305.3 million. Meren 52 received an additional payment of $24.4 million on January 31, 2025, pursuant to the Securitization 
Agreement. Given no comprehensive resolution was reached by December 27, 2024, Meren 52 has recognized its portion of the security 
deposit and the additional receivable under the Securitization Agreement as other operating income on December 27, 2024. The process of 
implementing a new tract participation by the parties is ongoing and is subject to government approval. The parties will continue discussions to 
seek final resolution of the formal redetermination of the Agbami tract participation in respect of the period after December 27, 2024, however 
there is no certainty that such ongoing discussions will result in a final resolution. 
Under the amended joint sale agreement between (among others) BTG Holding and the seller dated October 31, 2018, the seller could 
potentially claim that, given an additional payment has been received under the Securitization Agreement, this triggers a payment obligation 
of $54.6 million, exclusive of interest, capital taxes and certain deductions, contingent upon various criteria, with the outcome of this potential 
claim uncertain. Management considers the likelihood of any interest being payable to be unlikely. The Company has recorded an indemnity 
asset of $21.6 million under the deed of indemnity entered into between a subsidiary of the Company and BTG Oil & Gas for any costs suffered 
or incurred above $33.0 million post completion of the amalgamation, with the deed of indemnity backed by a $22.0 million letter of credit 
granted in favour a subsidiary of the Company. The letter of credit will remain in place for an initial period of two years and if a claim is not 
resolved in two years or is made after the two year period BTG Oil & Gas has undertaken to extend or reinstate the letter of credit. 
WITHDRAWAL FROM KENYA:
On May 23, 2023, the Kenya entities along with TotalEnergies submitted withdrawal notices to the remaining joint venture party on Blocks 
10BB, 13T and 10BA in Kenya, to unconditionally and irrevocably, withdraw from the entirety of the JOAs and PSCs for these concessions. The 
Company concurrently submitted notices to Ministry of Energy and Petroleum, requesting the government's consent to transfer all of its rights 
and future obligations under the PSCs to its remaining joint venture party. Government consent to the transfer was received on September 
18, 2025, and the Company subsequently transferred all of its rights and future obligation of Blocks 10BB, 13T and 10BA to its remaining joint 
venture party with effect on and from June 30, 2023. In accordance with the JOA and PSC the Company retains economic participation for 
activities prior to June 30, 2023, which might result in additional costs for the Company. The Company continues to monitor the claim made 
against the operator by local communities in relation to past operations which may relate to the period prior to June 30, 2023. No provision has 
been recognized for this as at December 31, 2025. 
SECURITIES AND GUARANTEES:
Under the conditions of the RBL facility, the main security package is comprised of security over the shares, production assets, contracts and 
rights of the Nigerian entities Meren 52 and Meren 234, cash and cash equivalents in the amount of $154.6 million as per December 31, 2025, 
that are held within the project accounts in Nigeria and The Netherlands, proceeds from the oil cargos sold and proceeds from the intercompany 
receivables between the Company and the Nigerian entities. Further, any and all claims relating to, and all returns of premium in respect of, all 
relevant insurance policies have been secured.
COMMITMENTS FROM FORWARD SALES:
The Group uses a mix of financial derivatives and physical forward sales contracts to manage its commodity price risk and ensure stability in 
cash flows. Its strategy is to hedge between 70-100% of its post-tax net entitlement production for the next 12-months. As at December 31, 
2025, two cargos of the Group’s expected lifted entitlement production for 2026 are covered by forward contracts. The average cargo lifted is 
for 1 million barrels of oil. The Group’s triggers for these two cargos covered by forward contracts have been triggered at an average of $62.1 
per barrel.

===== SIDA 26 =====

Report to Shareholders  |  December 31, 2025
PAGE 26
CRITICAL ACCOUNTING ESTIMATES 
The Company’s critical accounting estimates are defined as those estimates that have a significant impact on the portrayal of its financial 
position and operations and that require management to make judgements, assumptions and estimates in the application of IFRS Accounting 
Standards. Judgements, assumptions and estimates are based on historical experience and other factors that management believes to be 
reasonable under current conditions. As events occur and additional information is obtained, these judgements, assumptions and estimates may 
be subject to change. 
USE OF ESTIMATES 
The preparation of the consolidated financial statements in conformity with IFRS Accounting Standards requires management to make 
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the 
date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Such estimates 
include unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ 
from these estimated amounts as future confirming events occur. Significant estimates used in the preparation of the consolidated financial 
statements include, but are not limited to, recovery of exploration costs capitalized in accordance with IFRS Accounting Standards, equity 
method accounting, valuation and impairment of equity investments and contingent consideration arising from the acquisition of Meren Coop. 
The Company’s material accounting policies can be found in the Company’s audited consolidated financial statements for the years ended 
December 31, 2024, and December 31, 2025.
CLASSIFICATION OF JOINT ARRANGEMENTS
The Group is a party to transactions of non-operated Production Sharing Agreements (“PSAs”). The PSA transactions include the Group’s 
proportionate share of the PSAs assets, liabilities and expenses, with items of a similar nature on a line-by-line basis, from the date that 
participation in the PSA arrangements commenced. 
The Group has applied judgment in determining that it has joint control over the PSAs. This determination recognizes that all major decisions 
outside the original scope of the operations require unanimous approval by at least the Group and one or more of the PSAs partners. 
The Group has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions of 
the arrangement, such as approval of the capital expenditure program for each year and appointing, remunerating and terminating the key 
management personnel or service providers of the joint arrangement. The considerations made in determining joint control are similar to those 
necessary to determine control over subsidiaries. 
Classifying the arrangement requires the Group to assess its rights and obligations arising from the arrangement. Specifically, the Group 
considers: 
 ● The structure of the joint arrangement – whether it is structured through a separate vehicle. 
 ● When the arrangement is structured through a separate vehicle, the Group also considers the rights and obligations arising from: 
 ● The legal form of the separate vehicle; 
 ● The terms of the contractual arrangement; 
 ● Other facts and circumstances (when relevant). 
As the Group has a proportionate share of the rights to the PSAs’ assets and the obligations for the PSAs’ liabilities, it classifies these interests 
as a Joint Operation under IFRS 11, and presents its proportionate share of the assets, liabilities, revenues and expenses on a line-by-line basis 
in the consolidated financial statements.
This assessment often requires significant judgement, and a different conclusion on joint control and also whether the arrangement is a joint 
operation or a joint venture, may materially impact the accounting. 
If the Group did not have both joint control and a proportionate share of the rights to the PSAs’ assets and obligations for the PSAs’ liabilities, it 
would present only its net investment in the PSAs and its proportionate share of the PSAs’ net income in the consolidated financial statements.

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Report to Shareholders  |  December 31, 2025
PAGE 27
CRITICAL ACCOUNTING ESTIMATES - CONTINUED
ACCOUNTING FOR LEASES AND JOINT OPERATIONS 
Where the Group participates in a joint operation, either as a lease operator or non-operator party, determining whether to recognize and 
whether to measure a lease obligation involves judgement and requires identification of which entity has primary responsibility for the lease 
obligations entered into in relation to the joint operation’s activities. 
Where the joint operation (including all parties to that arrangement) has the right to control the use of the identified asset and all parties have 
a legal obligation to make payments to the third-party supplier, each joint operation participant would recognize its proportionate share of the 
lease related balances. This may arise where all parties to an unincorporated joint operation sign the lease agreement, or the joint operation is 
some sort of entity or arrangement that can sign in its own name. 
However, where the Group is the lead operator and the sole signatory such that it is the one with the legal obligation to pay the third-
party supplier, it would recognize 100% of the lease-related balances on its balance sheet. The Group would then need to assess whether 
the arrangement with the non-operator parties contains a sublease. This assessment would be based on the terms and conditions of each 
arrangement and may be impacted by the legal jurisdiction in which the joint arrangement operates.
Regardless of whether there is a sublease or not, the Group, in case it acts as the lead operator, would continue to recognize the lease liability 
for as long as it remains a party to the arrangement with the third-party supplier and has primary obligation to the lease payments.
CONSOLIDATION OF ENTITIES
When assessing control over a subsidiary, the Company is required to consider the nature of its relationship with the subsidiary, and whether 
strategic and operating decisions made by the subsidiary are made independently without the significant influence or control of the Company. 
Factors considered when assessing for control include share ownership, board composition and management involvement in the business. The 
determination of whether strategic and operating decisions made by the Company’s subsidiaries (see note 27) are made independently without 
the significant influence or control of the Company requires judgement.
VALUATION OF INVESTMENTS
An investment in an associate or a joint venture is accounted for using the equity method from the date on which the investee becomes an 
associate or a joint venture. Investments in associates or joint ventures are initially recorded at cost. On acquisition of the investment in an 
associate or a joint venture, any excess of the cost of the investment over the share of the net fair value of the identifiable assets and liabilities 
of the investee is recognized as notional goodwill, which is included within the carrying amount of the investment. Significant assumptions 
developed by management used to determine the fair value of the non-current assets include estimates for the quantity of proved and probable 
petroleum reserves, future commodity prices, operating and capital costs as well as discount rates. The proved and probable petroleum reserves 
are prepared by the investee’s independent petroleum engineers (management’s experts). 
Where contingent consideration has been recognized in an investment in an associate or joint venture, any revisions to the contingent 
consideration estimates after the date of acquisition, which have been considered as changes in estimates in accordance with IAS 8, are 
accounted for on a prospective basis. Any change in the liability as a result of the revised cash flows is adjusted to the cost of the asset and, 
in accordance with paragraph 37 of IAS 8, recognized as part of the associate or joint venture carrying amount rather than in profit or loss.
IMPAIRMENT OR REVERSAL OF IMPAIRMENT OF JOINT VENTURES AND ASSOCIATES
The amounts for investments in joint ventures and associates represents the Company’s equity interest in other entities, where there is either 
joint control or significant influence. The Company assesses investments in associates for impairment whenever changes in circumstances 
or events indicate that the carrying value may not be recoverable.  The process of determining whether there is an objective evidence of 
impairment considering circumstances or events which indicate that the carrying value may not be recoverable or calculating the recoverable 
amount requires judgement.  
An area in which the Company applied judgement prior to the completion of the transaction with BTG Oil & Gas to consolidate its interest 
in Meren Coop relates to the equity investment in joint venture. On acquisition, judgements and estimates were used in determining fair 
values on acquisition for the purposes of the notional purchase price allocation. Subsequently, in assessing whether there were any indicators 
of impairment the Company considered any effects of Meren Coop’s forward sales, the loan facility, and any operational and contractual 
implications on the future dividend stream when assessing for impairment indicators. 
An area in which the Company has applied judgement relates to the equity investments in associates. In assessing whether there are any 
indicators of impairment the Company considered the movements in share price of the associates listed on public markets, the results of 
exploration and appraisal activities and future plans for the operations

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Report to Shareholders  |  December 31, 2025
PAGE 28
CRITICAL ACCOUNTING ESTIMATES - CONTINUED
HYDROCARBON RESERVE AND RESOURCE ESTIMATES
Oil and gas production assets, including facilities, are depreciated on a units-of-production (“UoP") basis at a rate calculated by reference to 
total proved and probable oil and gas reserves (“2P”) determined in accordance with the principles contained in the SPE Petroleum Resources 
Management Reporting System (“PRMS”) framework. 
The Company estimates its 2P reserves based on information provided by reputable independent petroleum engineers, through the information 
provided by the respective operators. This information from reputable independent petroleum engineers concerns, amongst others, the 
geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery 
rates. 
2P reserves are determined using estimates of oil and gas in place, recovery factors, operating expenses, future development costs and future 
commodity prices; the latter having an impact on the total amount of recoverable reserves and the proportion of the gross reserves which are 
attributable to the host government under the terms of the Production-Sharing Agreements. 
The current long-term Brent oil price assumption used in the estimation of proved and probable reserves is based on the IQRE long-term oil 
price forward curve. 
As the economic assumptions used may change and, as additional geological information is obtained during the operation of a field, estimates 
of recoverable reserves may change.
UNITS-OF-PRODUCTION DEPRECIATION OF OIL AND GAS PROPERTIES
Oil and gas properties are depreciated using the UoP-method over total estimated proved and probable hydrocarbon reserves. This results in a 
depletion charge that is proportional to the depletion of the anticipated remaining production from the field. 
The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically 
recoverable reserves of the field at which the asset is located. These calculations require the use of estimates and assumptions, including the 
amount of recoverable reserves. 
The calculation of the UoP-rate of depreciation could be impacted to the extent that actual production in the future is different from current 
forecast production based on total estimated proved and probable reserves, or future capital expenditure estimates change. 
Changes to proven and probable reserves could arise due to changes in the factors or assumptions used in estimating reserves, including the 
effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions or unforeseen 
operational issues.
EXPLORATION AND EVALUATION COSTS
Exploration and evaluation costs are initially capitalized as intangible exploration assets with the intent to establish commercially viable 
reserves. The Company is required to make significant estimates and judgements about the future events and circumstances regarding whether 
the carrying amount of intangible exploration assets exceeds its recoverable amount (see note 6).  
The carrying amounts of the Company’s exploration and evaluation costs are reviewed at each reporting date to determine whether there is any 
indication of impairment. Exploration and evaluation assets are assessed for impairment if facts and circumstances suggest that the carrying 
amount exceeds the recoverable amount. Should the carrying amount exceed the recoverable amount, an impairment loss is recognized. 
Significant assumptions developed by management used to determine the recoverable amount include estimates for the quantity of contingent 
resources, future commodity prices, production forecasts, operating expenses, development costs, the likelihood of a successful farm out 
process, the timing of financial investment decision (“FID”) and the discount rate. The contingent resources and production rates are prepared 
by the Company’s independent petroleum engineers (management’s experts). 
Exploration and evaluation assets are assessed if facts and circumstances suggest that an impairment loss recognized in prior periods may no 
longer exist or may have decreased. An impairment reversal is recognized if there has been an increase in the asset’s recoverable amount since 
the last impairment loss was recognized.  
The changing worldwide demand for energy could result in a change in the assumptions used to determine the recoverable amount and 
could affect estimating the future cash flows which could impact the carrying amount of the Company’s intangible exploration assets. The 
timing of when global energy markets transition from carbon-based sources to alternative energy sources is highly uncertain. Environmental 
considerations are built into our estimates through the use of significant assumptions in estimating fair value including future commodity prices 
and discount rates. The energy transition could impact the future prices of commodities and discount rates used to appraise oil and gas projects. 
Pricing assumptions used in the determination of recoverable amounts incorporate market expectations and the evolving worldwide demand 
for energy

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Report to Shareholders  |  December 31, 2025
PAGE 29
PROVISION FOR SITE RESTORATION
Amounts used in recording a provision for site restoration are based on current legal and constructive requirements and current technology 
and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future 
cash outflows in relation to the site decommissioning and restoration can be difficult. To reflect the effects due to changes in legislation 
requirements, technology and price levels, the carrying amounts of site restoration provisions are reviewed on a regular basis.
On fields where the Group is required to contribute to site restoration costs, a provision is recorded to recognize the future commitment. An 
asset is created, as part of oil and gas interests, to represent the discounted value of the anticipated site restoration liability and depleted over 
the life of the field on a unit of production basis. The corresponding accounting entry to the creation of the asset recognizes the discounted 
value of the future liability. The discount applied to the anticipated site restoration liability is subsequently released over the life of the field 
and is charged to finance expense. Changes in site restoration costs and reserves are treated prospectively and consistent with the treatment 
applied upon initial recognition (see note 14).
REVENUE RECOGNITION 
Judgement is required in determining when and how much revenue to recognize from contracts with customers. While the Group has determined 
that all revenue from contracts with customers is earned at a point in time, there is judgement involved in this consideration. Contractual 
arrangements for the sale of different products or with different terms may result in revenue being recognized over time. 
There is also judgement involved in assessing whether the Group is the principal or agent in revenue transactions. In determining that the Group 
is acting as principal, the terms of the agreements were carefully considered and it was concluded that the Group controls the product before 
it is transferred to the customer. In alternate arrangements, the Group could be determined to be acting as agent. 
Under the terms of existing contracts, the Group has determined that shipping or transportation services are not being provided to the 
customer, and that the only performance obligations are for the sale of crude oil and natural gas. Judgement is required in determining whether 
shipping is being provided as a service, and this impacts on the identification of performance obligations, whether all performance obligations 
are recognized at a point in time or over time, and the overall timing of revenue recognition.
Finally, judgement is required to determine whether the contractual arrangements contain only variable consideration, or also embedded 
derivatives, and if variable consideration, whether to exercise the constraint.
TAXES
Judgement is required to determine which arrangements are considered to be a tax on income as opposed to production costs. Judgement is 
also required to determine whether deferred tax assets are recognized in the statement of financial position. Deferred tax assets, including 
those arising from tax losses carried forward, require management to assess the likelihood that the Group will generate sufficient taxable 
earnings in future periods in order to utilize recognized deferred tax assets. 
Assumptions about the generation of future taxable profits depend on management’s estimates of future cash flows. These estimates of future 
taxable income are based on forecast cash flows from operations (which are impacted by production and sales volumes, oil and gas prices, 
reserves, production costs, decommissioning costs, capital expenditure, dividends and other capital management transactions) and judgement 
about the application of existing tax laws in each jurisdiction. 
To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Group to realize the net deferred 
tax assets recorded at the reporting date could be impacted. In addition, future changes in tax laws in the jurisdictions in which the Group 
operates could limit the ability of the Group to obtain tax deductions in future periods.
SHARE BASED COMPENSATION
The estimated fair value of Performance share units (“PSUs”) is calculated based on non-market performance conditions set by the Company 
which are initially determined at the time of grant. The Company assesses the progress of reaching the individual performance conditions during 
each reporting period. PSUs cliff vest three years from the date of grant, at which time the Board of Directors will assign a performance multiple 
ranging from nil to 200% to determine the ultimate vested number of PSUs. The awards are revalued every quarter based on the Company’s 
share price and an estimate of the performance conditions at the quarter end. It is anticipated that PSU settlements will be made by issuing 
shares from treasury or cash, at the discretion of the Board of Directors (see note 21). 
The estimated fair value of the Restricted share units (“RSUs”) is initially determined at the time of grant. The awards are revalued every quarter 
based on the Company’s share price. RSUs may be settled in shares issued from treasury or cash, at the discretion of the Board of Directors 
(see note 21).
GOING CONCERN
The consolidated financial statements for the year ended December 31, 2025, have been prepared on a going concern basis, which assumes 
that the Company will be able to realize its assets and discharge its liabilities in the normal course of business as they become due.
CRITICAL ACCOUNTING ESTIMATES - CONTINUED

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Report to Shareholders  |  December 31, 2025
PAGE 30
INTERNAL FINANCIAL REPORTING AND 
DISCLOSURE CONTROLS
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company 
in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and 
reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information 
required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted under securities legislation is 
accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate 
to allow timely decisions regarding required disclosure. Due to the amalgamation discussed above completed on March 19, 2025, the Company’s 
disclosure controls and procedures have been updated to reflect the amalgamated disclosure controls and procedures.
Management, including the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of 
the Company’s disclosure controls and procedures. As of December 31, 2025, the Chief Executive Officer and Chief Financial Officer have each 
concluded that the Company’s disclosure controls and procedures, as defined in NI 52-109 - Certification of Disclosure in Issuer’s Annual and 
Interim Filings, are effective to achieve the purpose for which they have been designed.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
Internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and 
the preparation of financial statements in accordance with IFRS Accounting Standards. Management is also responsible for the design of the 
Company’s internal control over financial reporting in order to provide reasonable assurance regarding the reliability of financial reporting and 
the preparation of financial statements for external purposes in accordance with IFRS Accounting Standards.
The Company’s internal controls over financial reporting include policies and procedures that: pertain to the maintenance of records that, in 
reasonable detail accurately and fairly reflect the transactions and disposition of assets; provide reasonable assurance that transactions are 
recorded as necessary to permit preparation of the financial statements in accordance with IFRS Accounting Standards and that receipts and 
expenditures are being made only in accordance with authorization of management and directors of the Company; and provide reasonable 
assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect 
on the financial statements. Due to the amalgamation discussed above completed on March 19, 2025, the Company’s disclosure controls and 
procedures have been updated to reflect the amalgamated disclosure controls and procedures.
Management, including the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of 
the Company’s internal controls over financial reporting. As at December 31, 2025, the Chief Executive Officer and Chief Financial Officer have 
each concluded that the Company’s internal controls over financial reporting, as defined in NI 52-109 - Certification of Disclosure in Issuer’s 
Annual and Interim Filings, are effective to achieve the purpose for which they have been designed. Because of their inherent limitations, 
internal controls over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Furthermore, 
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes 
in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
ADVISORY REGARDING OIL AND GAS 
INFORMATION
The terms boe (barrel of oil equivalent) and MMboe (millions of barrels of oil equivalent) are used throughout this report. Such terms may 
be misleading, particularly if used in isolation. The conversion ratio of six thousand cubic feet per barrel (6 Mcf:1 Bbl) of conventional natural 
gas to barrels of oil equivalent and the conversion ratio of 1 barrel per six thousand cubic feet (1 Bbl:6 Mcf) of barrels of oil to conventional 
natural gas equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a 
value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to conventional natural gas 
is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
In this report, references are made to historical and potential future oil production in Nigeria and Namibia. In all instances these references are 
to light and medium crude oil category in accordance with NI 51-101 and the COGE Handbook.
Reserves are estimated remaining quantities of petroleum anticipated to be recoverable from known accumulations, as of a given date, based on 
the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which 
are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates 
and may be sub-classified based on development and production status. Proved Reserves are those quantities of petroleum, which, by analysis 
of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, 
from known reservoirs and under existing economic conditions, operating methods and government regulations. Probable Reserves are those 
additional quantities of petroleum that are less certain to be recovered than Proved Reserves, but which, together with Proved Reserves, are as 
likely as not to be recovered. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is 
unlikely that actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

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Report to Shareholders  |  December 31, 2025
PAGE 31
RISK FACTORS
With Board oversight, the Company proactively manages the identification, assessment and mitigation of risks, many of which are common to 
operations in the oil and gas industry as a whole, whilst others are unique to the Company. The realization of any of the risks listed below could 
have a material adverse effect on the Company’s business, financial condition, reserves and results of operations, such list being non-exhaustive. 
Risks that can materially affect the figures presented and disclosed in the Financial Statement and MD&A are described in the Company’s 
Annual Information Form for the year ended December 31, 2025 (”AIF”) available on SEDAR+ at www.sedarplus.ca or on Meren’s website at 
www.mereninc.com/investor-summary/financial-reports-meetings-filings/.
The risks noted in the risk factors section comprises those that can materially affect the figures presented and disclosures in the Financial 
Statements and MD&A. The Company’s Annual Information Form contains a more comprehensive list of risks that can affect the Company. 
PRICES, MARKETS AND MARKETING OF CRUDE OIL AND NATURAL GAS
Crude oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are 
beyond the control of the Company. World prices for oil and gas have fluctuated widely in recent years. Any material decline in prices could have 
an adverse effect on the Company’s business and prospects. The Company may be required by government authorities to limit production due 
to OPEC+ quotas from time to time. The conflicts in Ukraine and the Middle East have impacted global markets and may continue to result in 
increased volatility in financial markets and commodity prices. The Company does not have a direct exposure to operations in Ukraine and the 
Middle East.
The Company may undertake hedging activities when efficient to do so, however, hedging may not fully mitigate, in whole or in part, the risk and 
effect of lower commodity prices or may limit upside in rising markets. 
The Company or its investee company’s ability to market its oil and gas may depend upon its ability to acquire space on vessels or in pipelines 
that deliver oil and gas to commercial markets. The Company could also be affected by deliverability uncertainties related to the proximity of 
its reserves to pipelines and processing and storage facilities and operational issues affecting such pipelines and facilities as well as government 
regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and gas and many other aspects of the oil and 
gas business.
HEDGING
The Group enters into agreements to receive fixed prices on its oil and gas production to offset the risk of revenue reduction if commodity 
prices decline. However, if commodity prices increase beyond the levels set in such agreements, the Group will not benefit from such increases. 
LIQUIDITY AND CASH FLOW
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity describes a company’s 
ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fulfil their work commitments 
in accordance with contractual obligations, and to be able to potentially acquire strategic oil and gas assets and face potentially unexpected 
liabilities. 
The Company could potentially issue debt or equity, extend its debt maturities and enter into farmout agreements to ensure it has sufficient 
available funds to meet current and foreseeable financial requirements. 
The Company actively monitors its liquidity to ensure that its cash flows and working capital are adequate to support these financial obligations 
and the Company’s capital programs. The Company will also adjust the pace of its activities to manage its liquidity position. Notwithstanding any 
mitigation efforts, the Company remains exposed to erosion of its balance sheet and revenues and may have difficulty in securing necessary 
funding, which may lead to insufficient liquidity.
CREDIT FACILITIES 
The Company is party to credit facilities. The terms of the facility contain covenants and restrictions on the ability of the Company to, among 
other things, incur or lend additional debt, pay dividends and make restricted payments, and encumber its assets. The failure of the Company 
to comply with the covenants contained in the facility or to repay or refinance the facility by its maturity date could result in an event of 
default, which could, through acceleration of debt, enforcement of security or otherwise, materially and adversely affect the operating results 
and financial condition of the Company. As disclosed in the Financial Statements, the Company’s revolving reserve-based loan (RBL) amortizes 
quarterly to the lower of commitments and the borrowing base assessment and matures on June 20, 2029. 
CREDIT RISK 
Credit risk is the risk of loss if counterparties do not fulfil their contractual obligations. Most of the Company’s credit exposure relates to 
amounts due from its JV parties and receivables from crude oil sales. Sales are predominantly to investment-grade counterparties or supported 
by letters of credit/guarantees. A portion of the Company’s cash is held by banks in foreign jurisdictions.

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Report to Shareholders  |  December 31, 2025
PAGE 32
INTEREST RATE RISK
The Company floating-rate borrowings that reference SOFR and therefore could be exposed to volatility in interest rates that could constrain 
the company’s cashflows. 
SUBSTANTIAL CAPITAL REQUIREMENTS 
Meren expects to make substantial capital expenditures for exploration, development and production of oil and gas reserves in the future. The 
Company’s ability to access the equity or debt markets may be affected by any prolonged market instability. The inability to access the equity or 
debt markets for sufficient capital, at acceptable terms and within required time frames, could have a material adverse effect on the Company’s 
financial condition, results of operations and prospects.
To finance its future acquisition, exploration, development and operating costs, the Company may require financing from external sources, 
including from the issuance of new shares, issuance of debt or execution of working interest farmout agreements. There can be no assurance 
that such financing will be available to the Company or, if available, that it will be offered on terms acceptable to the Company.
If additional financing is raised through the issuance of equity or convertible debt securities, control of the Company   may change and the 
interests of shareholders in the net assets of the Company may be diluted. If unable to secure financing on acceptable terms, the Company may 
have to cancel or postpone certain of its planned exploration and development activities which may ultimately lead to the Company’s inability 
to fulfil the minimum work obligations under the terms of its various concessions. Availability of capital will also directly impact the Company’s 
ability to take advantage of acquisition opportunities.
FINANCIAL STATEMENTS PREPARED ON A GOING CONCERN BASIS 
Meren’s financial statements have been prepared on a   going concern basis under which an entity is considered to be able to realize its assets 
and satisfy its liabilities in the ordinary course of business.  There can be no assurances that the Company will be successful in completing 
additional financings, achieving profitability or completing future transactions.  
RISKS INHERENT IN OIL AND GAS EXPLORATION, DEVELOPMENT, AND PRODUCTION
Oil and gas operations involve many risks, which, even with the combination of experience, knowledge and careful evaluation may not be able 
to overcome. The long-term commercial success of Meren depends on its ability to find, acquire, develop and commercially produce oil and gas 
reserves. No assurance can be given that the Company will be able to locate satisfactory properties for acquisition or participation. Moreover, 
if such acquisitions or participations are identified, the Company may determine that current markets, terms of acquisition and participation 
or pricing conditions make such acquisitions or participations uneconomic. It is difficult to project the costs of implementing an exploratory, 
appraisal or development drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with 
encountering various drilling conditions such as over pressured zones, tools lost in the hole, equipment failures or malfunctions and changes in 
drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. Without the continual 
addition of new reserves, any existing reserves associated with the    Company’s oil and gas assets at any particular time, and the production 
therefrom, could decline over time as such existing reserves are exploited. There is a risk that additional   commercial quantities of oil and gas 
may not be discovered or acquired by the Company. 
Meren’s business is subject to all the risks and hazards inherent in businesses involved in the exploration for, and the acquisition, development, 
production and marketing of, oil and gas, many of which cannot be overcome even with a combination of experience and knowledge and careful 
evaluation. The risks and hazards typically associated with oil and gas operations include fire, explosion, blowouts, sour gas releases, pipeline 
ruptures and oil spills, each of which could result in substantial damage to oil and gas wells, production facilities, other property, the environment 
or personal injury, and such damages may not be fully insurable.
RISKS ASSOCIATED WITH DISCOVERING HYDROCARBONS 
While the Company has historically made discoveries, there is no certainty that expenditures made on future exploration or development 
activities by Meren will result in discoveries of oil or gas in commercial quantities or that commercial quantities of oil and gas will be discovered, 
produced, or acquired by the Company. The portion of the Company’s portfolio, which include prospects & leads require additional data to fully 
define their potential and significant changes to the resource estimates will occur with the incorporation of additional data and information. 
There is no certainty that any discovered resources will be commercially viable to produce. There is no certainty that any portion of undiscovered 
resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. 
RISK FACTORS - CONTINUED

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Report to Shareholders  |  December 31, 2025
PAGE 33
RISKS ASSOCIATED WITH RESERVES AND RESOURCES VOLUME ESTIMATES 
In the event of a discovery, reservoir parameters, such as porosity, permeability, net hydrocarbon pay thickness, fluid composition and water 
saturation, may vary from those assumed by the Company’s independent third-party resource evaluator affecting the volume of hydrocarbon 
estimated to be present. Other factors such as the reservoir pressure, density and viscosity of the oil, solution gas/oil ratio, permeability, the 
presence or absence of water drive and the specific mineralogy of the reservoir rock will affect the volume of oil that can be recovered. Drill 
stem tests, or well tests, are commonly based on flow periods of one to five days and build up periods of one to three days to aid in understanding 
reservoir performance. Well test results include uncertainty and are not necessarily indicative of long-term performance or of ultimate recovery.
Furthermore, there are many uncertainties inherent in estimating quantities of oil and natural gas reserves and resources (contingent and 
prospective) and the future cash flows attributed to such reserves and resources. The actual production, revenues, taxes and development and 
operating expenditures with respect to the reserves and resources associated with the Company’s assets will vary from estimates thereof and 
such variations could be material. Estimates of reserves that may be developed and produced in the future are often based upon volumetric 
calculations and upon analogy to similar types of reserves rather than actual production history. There is uncertainty that it will be commercially 
viable to produce any portion of the contingent resources. Actual future net cash flows will be affected by other factors, such as actual 
production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, 
changes in governmental regulation or taxation and the impact of inflation on costs. 
RISKS ASSOCIATED WITH PRODUCTION GUIDANCE AND FORECASTING 
Production guidance includes uncertainty around reservoir and well performance, reliability of production and process facilities, success of 
future drilling programs and execution of planned maintenance activities. Completion of future wells does not ensure a profit on the investment 
or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of 
operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays 
in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage 
or transportation capacity or other geological and mechanical conditions. While structured maintenance plans, as well as close well, facility and 
operational supervision can contribute to maximizing production rates over time, production delays and declines from field operating conditions 
cannot be eliminated and may adversely affect production guidance, revenue and cash flow levels to varying degrees.
RISKS RELATING TO INFRASTRUCTURE
Meren is dependent on having available and functioning infrastructure relating to the properties and licenses on which it operates, such as roads, 
power and water supplies, pipelines and gathering systems, supply bases and associated services. 
The amount of oil and gas that the Company can produce, and sell is subject to accessibility, availability, proximity and capacity of gathering, 
processing and pipeline systems. The lack of availability of capacity or a failure in any of the gathering, processing and pipeline systems, and in 
particular the processing facilities could result in the Company’s inability to realize the full economic potential of its production or in a reduction 
of the price offered for the Company’s production. Any significant change in market factors, terms of use or other conditions affecting these 
infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm the Company’s 
business financial condition, results of operations, cash flows and future prospects.
In Nigeria, gas export relies on the continued safe operations at the Nigeria LNG facility. Gas export restrictions could have an adverse effect on 
oil production, due to reductions in overall facility production to minimise flaring of associated gas. The supply chain for offshore is dependent 
upon existing ports and onshore infrastructure. Several factors, including social unrest onshore, have the potential to disrupt both the gas 
processing facilities and the upstream supply chain which could have detrimental impacts on cashflows.
In Equatorial Guinea, exploration efforts in Block EG-31 are targeting gas prospects located close to existing gas export and processing facilities. 
In the event of a discovery, the discovered fluids may not be compatible with the existing processing facilities resulting in additional cost which 
may result in the potential discovery being non-commercial. There may also be insufficient ullage in the facilities to accept additional capacity 
and without appropriate commercial arrangements it may not be possible to produce any potential discovery.
RISKS ASSOCIATED WITH THE AVAILABILITY OF EQUIPMENT AND STAFF 
Meren’s oil and gas exploration and development activities are dependent on the availability of drilling and related equipment and qualified staff 
in the particular areas where such activities are or will be conducted. For any operated drilling or seismic activities, the Company would rely on 
the availability of leased drilling rigs or seismic equipment used for its exploration and development activities. Shortages of such equipment or 
staff may affect the availability of such equipment to the Company and may delay Meren’s exploration and development activities and result 
in lower production.
INCREASED COSTS AND SUPPLY DISRUPTION
A failure to secure the services and equipment necessary for the Company’s operations for the expected price, on the expected timeline, or 
at all, may have an adverse effect on the Company’s financial performance and cash flows. The Company’s operating and capital costs could 
escalate and become uncompetitive due to supply chain disruptions, inflationary cost pressures, equipment limitations, escalating supply costs, 
and additional government intervention through stimulus spending or additional regulations. The Company’s inability to manage costs may 
impact project returns and future development decisions, which could have a material adverse effect on its financial performance and cash 
flows.  In addition, with rising inflation levels combined with global cost of living expenses, the Company may be faced with the challenge of how 
to attract and retain employees.  Though Meren does not directly control procurement decisions associated with all of our assets, the Company 
works with its JV parties to ensure adequate contingency for cost inflation is incorporated into capital and operating budgets and that costs 
are controlled within budget.   
RISK FACTORS - CONTINUED

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Report to Shareholders  |  December 31, 2025
PAGE 34
SHARED OWNERSHIP AND DEPENDENCY ON JV PARTIES 
The Company’s operations are primarily conducted together with one or more JV parties through contractual arrangements, including 
unincorporated associations. In such instances, the Company may be dependent on, or affected by, the due performance and financial strength 
of its JV parties. If a JV party fails to perform or becomes insolvent, the Company may, among other things, risk losing rights or revenues or 
incur additional obligations or costs, experience delays, or be required to perform such obligations in place of its JV party. The Company and 
its JV parties may also, from time to time, have different opinions on how to conduct certain operations or on what their respective rights and 
obligations are under a certain agreement. If a dispute were to arise with one or more JV parties relating to a project, such dispute may have 
material adverse effect on the Company’s or investee company’s operations relating to such project.
RISKS RELATING TO CONCESSIONS, LICENSES AND CONTRACTS 
Meren’s operations are based on a relatively limited number of concession agreements, licenses and contracts. The rights and obligations under 
such concessions, licenses and contracts may be subject to interpretation and could also be affected by, among other things, matters outside 
the control of Meren. In case of a dispute, it cannot be certain that the view of the Company would prevail or that the Company otherwise 
could effectively enforce its rights which, in turn, could have significantly negative effects on Meren. Also, if the Company or any of its JV 
parties were found to have failed to comply with their obligations or liabilities under a concession, license or contract, including record-keeping, 
budgeting, and time scheduling requirements, the Company’s or JV parties rights under such concession, license or contract may be terminated 
or otherwise relinquished in whole or in part. The Company cannot guarantee that requirements are adequately met by its JV parties, which 
could bring an increased risk of impairment and reduced future cash flow.
In May 2023, the Company submitted notices to withdraw from its concessions on Blocks 10BB, 13T and 10BA in Kenya.  The Company’s 
withdrawal from the concessions is subject to approvals from the Kenyan authorities and, while the Company is working with its JV parties and 
the authorities to effect a smooth withdrawal process, there can be no certainty that such approvals will be forthcoming on terms acceptable 
to all parties. Any delay or adverse outcome in the withdrawal process could result in additional costs, disputes or claims, and may adversely 
affect the Company’s business, financial condition and results of operations.
GOVERNMENT REGULATIONS AND TAX RISK
The Company may be adversely affected by changes to applicable laws to which it is subject, and its host governments may implement new 
applicable laws, modify existing ones, or interpret them in a manner that is detrimental to the Company. Such changes to the laws to which the 
Company is subject could, amongst other things, result in a windfall tax, an increase in existing tax rates or the imposition of new ones or the 
Company may be subject to tax assessments, all of which on their own or taken together could have a material adverse effect on the Company’s 
business, financial condition, results of operations and prospects of the Company’s oil and gas assets.  
As has become customary in Nigeria since 2019, the annual budget for Nigeria has been accompanied by a proposed finance bill that supports 
the revenue needs indicated in the annual budget. This bill could include changes to tax laws, including laws that can affect directly or indirectly 
the oil and gas industry. 
Regulatory requirements affecting the oil and gas industry - including permitting rules, operational standards, local content requirements, and 
ongoing amendments to sector-specific legislation - may materially affect the Company’s operations, timing of approvals, costs of compliance, 
fiscal terms, and continued access to concessions. These regulatory developments are incorporated within the Company’s assessment of 
Government Regulations and Tax Risk.
INTERNATIONAL OPERATIONS 
Meren participates in oil and gas projects located in emerging markets, primarily in Africa. Oil and gas exploration, development and production 
activities in these emerging markets are subject to significant political, economic, and other uncertainties that may adversely affect the 
Company’s operations. The Company could be adversely affected by changes in applicable laws and policies in the countries where the Company 
has interests. Additional uncertainties include, but are not limited to, the risk of war, terrorism, expropriation, civil unrest, nationalization, 
renegotiation or nullification of existing or future concessions and contracts, the imposition of international sanctions, a change in crude oil or 
gas pricing policies, changes to taxation laws and policies, assessments and audits (including income tax) against the Company by regulatory 
authorities, difficulty or delays in obtaining necessary regulatory approvals, risks associated with potential future legal proceedings, and the 
imposition of currency controls. These uncertainties, all of which are beyond the Company’s control, could have a material adverse effect on 
the Company’s business, prospects and results of operations. In addition, if legal disputes arise related to oil and gas concessions acquired by 
the Company, they could be subject to the jurisdiction of courts other than those of Canada. The Company’s recourse may be very limited in 
the event of a breach by a government or government authority of an agreement governing a concession in which the Company acquires an 
interest. The Company may require licenses or permits from various governmental authorities to carry out future exploration, development 
and production activities. There can be no assurance that the Company will be able to obtain all necessary licenses and permits when required. 
FOREIGN CURRENCY EXCHANGE RATE RISK 
The Company is exposed to changes in foreign exchange rates as expenses in international subsidiaries, oil and gas expenditures, or financial 
instruments may fluctuate due to changes in rates. The Company’s exposure is partially offset by sourcing capital projects and expenditures in 
US dollars. The Company had no forward exchange contracts in place as at December 31, 2025. 
DECOMMISSIONING
The Company is responsible for compliance with all applicable laws, regulations and contractual requirements regarding the decommissioning, 
abandonment and reclamation of the Company’s assets at the end of their economic life.
RISK FACTORS - CONTINUED

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

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

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

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

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

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

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

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

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