Kvartalsrapport Q1 2025

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Suite 2500  
666 Burrard Street,  
Vancouver, B.C. Canada V6C 2X8   
info@africaoilcorp.com 
africaoilcorp.com 
 
 
* All dollar amounts in this press release are U.S. Dollars unless otherwise indicated. 
 
NEWS RELEASE 
AFRICA OIL ANNOUNCES FIRST QUARTER 2025 RESULTS AND 
DECLARES SECOND QUARTERLY DIVIDEND  
 
May 14, 202 5 (AOI–TSX, AOI –Nasdaq-Stockholm) – Africa Oil Corp.  (“Africa Oil” , “AOC”  or the 
“Company”) today published its financial and operating results for the three months ended March 31, 
2025, and is pleased to declare its second quarterly distribution of $25 million under its enlarged base 
dividend policy. 
 
Africa Oil President and CEO, Roger Tucker commented:  “During th e first  quarter, Africa Oil 
significantly transformed its scale and structure by completing the Prime amalgamation. This strategic 
move has  doubled our reserves and high -quality, high-netback production  and underpins our new 
enlarged shareholder returns policy. We are now poised for the Company’s next phase of value creation 
by monetizing our world-class assets and delivering compelling shareholder returns, as we continue to 
grow into a leading independent E&P.” 
Highlights* 
• Closed the amalgamation transaction to take full control of Prime, doubling AOC’s reserves and 
production, and implemented a new policy to effectively triple dividend per share. 
• During Q1 2025 (presented as if the amalgamation had closed on January 1, 2025): 
o Achieved average daily working interest(1) (“WI”) and entitlement(2) production of 33,400 
barrels of oil equivalent per day (“boepd”) and 37,700 boepd respectively, in line with 
expectations. 
o Sold five cargoes ( approximately 5 million barr els) at an average sales price of 
$79.5/bbl versus an average Dated Brent for the same period of $75.7/bbl. 
o Recorded cashflow from operations (3,4) before working capital adjustment of $ 99.8 
million.  
o Received a distribution of $31.6 million from Impact. 
o Proactively reduced the RBL debt balance by $130.0 million to $620.0 million at the 
end of Q1 2025, reducing interest expenses. 
o End of Q1 2025 cash balance of $428.4 million, resulting in a net debt position of $191.6 
million with a Net Debt/ EBITDAX(4) of 0.3x as at March 31, 2025. 
• During Q1 2025 with the amalgamation closing on March 19, 2025, recorded net income of 
$50.9 million ($0.11 per share5). 
• Post end of Q1 2025: 
o Distributed the first quarterly cash dividend of approximately $25.0 million ($0.0371 per 
share) in April 2025. 
o AOC’s Board has declared the second quarterly dividend of approximately $25.0 million 
($0.0371 per share) payable in June 2025 to shareholders of record at the close of 
business on May 26, 2025. 
o The Company reduced the RBL debt balance by a further $80.0 million and has 
commenced the process to cancel its $65.0 million Corporate Facility, which remains 
undrawn.

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2025 First Quarter Results 
Highlights 
The Company completed the Prime amalgamation on March 19, 2025. The following table presents the 
highlights for Q1 2025. 
  Three months ended 
 
 
Years ended 
AOC highlights(i,ii) Unit March 31, 2025 March 31, 2024 
 
December 31, 
2024 
     Net income/ (loss) $’m 50.9 3.5 (279.1) 
Net income/ (loss) per share 
– basic 
$/ share 0.11(5) 0.01 (0.62) 
     
Net debt position(iii) $’m 191.6 285.9 289.1 
     
WI production(iii) boepd 33,400 34,200 34,000 
Entitlement production(iii) boepd 37,700 40,200 38,800 
     
EBITDAX(iv) $’m 141.6 n/a n/a 
     
Cash flow from operations(3 iv) $’m 99.8 n/a n/a 
     
Free Cash Flow(iv) $’m 121.6 n/a n/a 
i. This table includes non -GAAP measures  (net debt, EBITDAX , cash flow from operations and free cash flow) . Definitions and 
reconciliations to these non -GAAP measures are provided on pages 14-16 of the Report to Shareholders  for the period ended March 
31, 2025. 
ii. WI and entitlement production, EBITDAX, cash flow from operations and free cash flow from operations are presented for Q1 2025 as 
if the amalgamation had closed on January 1, 2025.  
iii. Net debt position and production numbers as presented for the comparative periods includes 100% of Prime to be comparable wit h 
March 31, 2025. 
iv. EBITDAX, cash flow from operations and free cash flow  are reported for the year 2025 only as if the amalgamation had closed on 
January 1, 2025 
 
Constructed Prime information for purposes of explaining performance  
 
Constructed Prime information to explain performance is included in the following tables to present on 
a consolidated basis net income for Q1 2025 , and cash flow statement for Q1 2025 as if the 
amalgamation had closed on January 1, 2025, whereby the Africa Oil interim condensed consolidated 
statement of net income and comprehensive income and the Africa Oil interim condensed consolidated 
statement of  cash flows for Q1 2025 are combined with the Prime statement of net income and 
comprehensive income and the Prime statement of cash flows for the period until March 19, 2025. 
Adjustments are included to conform Prime financial information with Africa Oil accounting policies and 
for any transactions between Africa Oil and Prime prior to amalgamation for the purpose of presenting 
constructed Prime information to explain performance. 
 
 
Interim condensed consolidated statement of net income 
       
 For the three months ended  AOC Q1 
2025 per 
Financial 
Statements 
Prime for period from 
January 1, 2025, to 
March 19, 2025 
Adjustments (i) March 31, 
2025 
      
Revenue  76.4 323.5 - 399.9 
Cost of Sales       
 Production costs  (51.2) (187.4) 2.0 (236.6) 
 Depletion and decommissioning costs  (12.1) (71.3) - (83.4) 
   (63.3) (258.7) 2.0 (320.0) 
Gross profit  13.1 64.8 2.0 79.9 
 General and administrative expenses  (13.5) (6.2) - (19.7) 
Operating (loss) / profit  (0.4) 58.6 2.0 60.2 
 Finance income  1.1 2.4 - 3.5

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 Finance expense  (2.8) (21.3) - (24.1) 
Net financial items  (1.7) (18.9) - (20.6) 
 Share of profit from investment in joint venture  15.9 - (15.9) - 
 Share of loss from investments in associates  (2.0) - - (2.0) 
 Reversal of impairment of investment in joint venture  42.9 - (42.9) - 
Profit before tax  54.7 39.7 (56.8) 37.6 
Income tax  (3.8) (7.9) - (11.7) 
Net income attributable to common shareholders 50.9 31.8 (56.8) 25.9 
i. Adjustments to remove items related to Prime as fully consolidated above. 
  
 
 
Interim condensed consolidated statement of cash flows 
        
 For the three months ended  AOC Q1 
2025 per 
Financial 
Statements 
Prime for period from 
January 1, 2025, to 
March 19, 2025 
Adjustments (i)  March 31, 
2025 
       
Operations       
 Profit before tax  54.7 39.7 (56.8)  37.6 
 Adjustments as per financial statements  (55.6) 59.0 58.8  62.2 
Net cash (used) / generated in operating activities before 
working capital 
 (0.9) 98.7 2.0  99.8 
 Changes in working capital  37.3 (25.7) -  11.6 
Net cash generated in operating activities  36.4 73.0 2.0  111.4 
        
Investing       
 Expenditures on oil and gas properties  (3.6) (22.6) (2.0)  (28.2) 
 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  0.9 2.2 -  3.1 
 Cash acquired from Prime consolidation (ii)  380.4 - (381.3)  (0.9) 
Net cash generated/ (used) in investing activities  473.8 (20.4) (443.3)  10.1 
       
Financing       
 Repayment RBL Facility  (130.0) - -  (130.0) 
 Repayment of principal portion of lease 
commitments 
 (0.1) - -  (0.1) 
 Dividends paid to shareholders  - (120.0) 120.0  - 
 Repurchase of share capital  (8.3) - -  (8.3) 
 Interest expense paid  (4.9) (10.8) -  (15.7) 
Net cash used in financing activities  (143.3) (130.8) 120.0  (154.1) 
      
Foreign exchange variation on cash and cash equivalents 0.1 - -  0.1 
      
Total cash flow 367.0 (78.2) (321.3)  (32.5) 
      
Cash and cash equivalents, beginning of the period 61.4 399.5 -  460.9 
Cash and cash equivalents, end of the period 428.4 321.3 (321.3)  428.4 
i. Adjustments to remove items related to Prime as Prime fully consolidated above  
ii. Reflects impact of net cash movement on the level of BTG Pactual Holding S.à.r.l.    
 
Outlook 
Shareholder Returns  
 
The Company is pleased to announce that its Board has declared the distribution of the Company’s 
second 2025 quarterly cash dividend of approximately $25.0 million or $0.0371 per share. This dividend 
will be payable on June 11, 2025, to shareholders of record at the close of business on May 26, 2025.  
This dividend qualifies as an ‘eligible dividend’ for Canadian income tax purposes. Dividends for shares 
traded on the Toronto Stock Exchange (“TSX”) will be paid in Canadian dollars on June 11, 2025; 
however, all US and foreign shareholders will receive U SD funds. Dividends for shares traded on

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Nasdaq Stockholm will be paid in Swedish Krona in accordance with Euroclear principles on June 16, 
2025. 
To execute the payment of the dividend, a temporary administrative cross border transfer closure will 
be applied by Euroclear from May 22, 2025, up to and including May 26, 2025, during which period 
shares of the Company cannot be transferred between the TSX and Nasdaq Stockholm.  
Payment to shareholders who are not residents of Canada will be net of any Canadian withholding 
taxes that may be applicable. For further details, please visit: https://africaoilcorp.com/investor -
summary/total-shareholder-returns/.  
Future dividend declarations are subject to customary Board approval and consents.  
Nigeria 
The Company remains focused on working with its JV partners to sustain and enhance production 
through targeted drilling and optimisation initiatives on its three producing fields in deepwater Nigeria.  
At Egina, two producers were drilled in Q1 2025 with both expected to come onstream in Q2 2025. On 
Akpo, a well intervention and the drilling of one development well are planned for Q2 2025.  A planned 
break to the rig campaign is planned from Q4 2025 to allow for interpretation of the available 4D seismic 
data and drilled well results to enable maturation of future infill drilling candidates.  
The Company’s Nigerian portfolio includes infrastructure -led exploration assets that in case of 
commercial discovery success, could potentially present attractive short cycle, high return investment 
opportunities that would benefit from the existing facili ties. One such opportunity , which  is being 
progressed towards drilling is  the Akpo Far East prospect  with an unrisked, best estimate, gross field 
prospective resource volume of 143.6 MMboe . The targeted hydrocarbons are predicted to be light, 
high gas-oil ratio (“GOR”) oil equivalent to those found in the Akpo field. If successful, initial production 
could be achieved from existing production manifolds with the potential to materially incre ase reserves 
on the Akpo Field.  
At Agbami, further planned maintenance including a full field shutdown in Q4 2025, is expected to 
support long-term performance with 4D seismic interpretation continuing in support of the upcoming 
drilling campaign. Rig and well long lead items contracting  is underway, alongside the placement of 
orders for subsea trees, in preparation for the commencement of the infill drilling campaign in 2027.  
For Preowei, studies of the fast-track seismic data are continuing to further derisk the identified upside 
opportunities to enhance recoverable volumes. In parallel, the reengagement of the front -end 
engineering and design (“FEED”) contractor is planned in order to carry out additional evaluation aimed 
at optimizing the Preowei engineering, procurement, construction and installation (“EPCI”) phase costs. 
Namibia Orange Basin Appraisal and Exploration Campaign 
The Venus Field is expected to be the first development area in Block 2913B. The Venus development 
plan is for up to 40 subsea wells tied back to a floating production, storage and offloading (“FPSO”) 
platform that can handle peak output of 160,000 barrels per day of oil.  
Key near-term project preparation and decision-making processes are:  
o Front-End Engineering Designs (“FEED”): Q2 – Q4 2025 
o ESIA submission to authorities: Q4 2025 
o Final Investment Decision (“FID”) could be made during H1 2026  
The latest exploration drilling campaign was completed on April 25, 2025, with the drilling rig 
demobilized. The Company expects the next drilling campaign to commence during Q4 2025 and notes 
that TotalEnergies has publicly identified Olympe -1X, on Block 2912, as a possible target for this 
campaign. 
 
South Africa Orange Basin, Block 3B/4B

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Following the granting of an Environmental Authorization for exploration activities (drilling of up to 5 
exploration wells) by the Department of Mineral Resources and Energy for the Republic of South Africa 
on September 16, 2024, the legislative notification and appeals process continues to progress with the 
relevant regulatory agencies. The operator has stated that with the approval process progressing the 
current plan is to drill the first exploration well on Block 3B/4B in 2026 and has identified Nayla, a 
prospect that lies in the northwest of the license area as the potential drilling target.  
Equatorial Guinea, EG-18 and EG-31 
The Company is in active dialogue with industry parties to attract farm in parties on both blocks, with 
the aspiration of completing the exercise by the end of Q3 2025. 
If the Company is successful in attracting farminee partner(s) for these blocks, subject to customary 
consents and approvals including governmental and regulatory permissions, the Company anticipates 
that newly formed JVs could plan for exploration drillin g in late 2026 or during 2027. However, there is 
no guarantee the Company can secure farminee partners on acceptable terms and it does not intend 
to undertake exploration drilling on a sole risk basis if it is unsuccessful in its farm down campaign.  
Summary of 2025 Management Guidance and Actuals 
The Company’s full -year 2025 Management Guidance is unchanged and is repeated here for 
completeness. These estimates are based on a 2025 average Brent price of $75.0 per barrel. At an 
average Brent price of $85.0 per barrel the mid -point of the cash flow from operations guidance range 
is estimated to increase by approximately 19%, and at an average of $65.0 per barrel the mid -point is 
estimated to decrease by approximately 12%.  
 2025 Guidance Q1 2025 actuals 
WI production (boepd) (1) 28,000 – 33,000 33,400 
Entitlement production (boepd) (2) 32,000 – 37,000 37,700 
EBITDAX ($ million) (4) 500 - 600 141.6 
Cash flow from operations ($ million) (3,4) 320 - 370 99.8 
Capital investment ($ million) 150 - 190 28.2 
 
Notes 
1. Aggregate oil equivalent production data comprised of light and medium crude oil and conventional natural gas 
production net to Prime’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, tax oil , 
royalty oil and profit oil and is different from working interest production that is calculated based on project volumes 
multiplied by Prime’s effective working interest in each license. 
3. Cash flow from operations before working capital and interest payments. 
4. Non-GAAP measures. Definitions and reconciliations to these non -GAAP measures are provided on pages 14-16 of 
the Report to Shareholders for the period ended March 31, ,2025. 
5. Based on the Q1 2025 weighted average number of shares outstanding of 449,431,803. 
Management Conference Call 
Senior management will hold a conference call to discuss the results on Friday, May 16, 2025, at 09:00 
(EST) / 14:00 (GMT) / 15:00 (CET). The conference call may be accessed by dial in or via webcast.  
 
Participants should use the following link to register for the live webcast:  
 
https://webcasting.buchanan.uk.com/broadcast/680f944fc26db8001247cb6f  
 
Participants can also join via telephone with the instructions available on the following link: 
 
https://url.de.m.mimecastprotect.com/s/FC-zC46A74ulzjgU3Hyc4JuC-?domain=urldefense.com 
   
1. Click on the call link and complete the online registration form.

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2. Upon registering you will receive the dial-in info and a unique PIN to join the call as well as an 
email confirmation with the details.   
 
About Africa Oil 
Africa Oil is a full -cycle Independent upstream oil and gas company with interests offshore Nigeria, 
Namibia, South Africa and Equatorial Guinea. Its main assets are producing and development assets 
in deepwater Nigeria operated by Majors. The Company holds a leading position in the Orange Basin 
including its effective interest in the Venus light oil project, offshore Namibia, and its direct interest in  
Block 3B/4B, offshore South Africa. The Company is listed on the Toronto Stock Exchange and on 
Nasdaq Stockholm under the symbol "AOI". 
 
For further information, please contact: 
 
Shahin Amini 
Head of IR and Communications 
shahin.amini@africaoilcorp.com 
T: +44 (0)20 8017 1511 
 
Burson Buchanan  
Financial PR & Communications Advisor   
Energy@Buchanan.uk.com  
T: +44 (0)20 7466 5000  
 
Additional Information  
This information is information that Africa Oil is obliged to make public pursuant to the EU Market Abuse Regulation. 
The information was submitted for publication, through the agency of the contact persons set out above, at 5:00 
p.m. EST on May 14, 2024. 
 
Advisory Regarding Oil and Gas Information 
The terms boe  (barrel of oil equivalent) is used throughout this press release. Such terms may be misleading, 
particularly if used in isolation. Production data are based on a conversion ratio of six thousand cubic feet per barrel 
(6 Mcf: 1bbl). This conversion ratio i s based on an energy equivalency conversion method primarily applicable at 
the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the 
current price of crude oil as compared to natural gas is significa ntly different from the energy equivalency of 6:1, 
utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Petroleum references in this 
press release are to light and medium gravity crude oil and conventional natural gas in accordance with NI 51-101 
and the COGE Handbook. 
  
Estimates of reserves in this press release were prepared using guidelines outlined in the Canadian Oil and Gas 
Evaluation Handbook and in accordance with National Instrument 51 -101 – Standards of Disclosure for Oil and 
Gas Activities. The reserves estimates disclosed in this press release are estimates only and there is no guarantee 
that the estimated reserves will be recovered. 
Forward-Looking Information 
Certain statements and information contained herein constitute "forward -looking information" (within the meaning 
of applicable Canadian securities legislation) , including statements related to: the enlarged base dividend 
distribution; the declaration of the $25 million quarterly dividend;  schedules and costs of drilling activity  including 
those offshore Namibia and Nigeria;  the outcome and timing of exploration, appraisal and development activities 
including those offshore Namibia and Nigeria; the development of the Venus discovery; the ability of Africa Oil to 
secure farminee partners on acceptable terms in Equatorial Guinea; the ability of Africa Oil to deliver further growth 
or increased shareholder returns including by monetizing its assets; the ability of Africa Oil to grow into a leading 
independent E&P; the continuing benefits from funded, high value growth opportunities, including the Venus oil 
project in the Orange Basin ; expectations regarding free -cash flow ; the ability of Africa Oil to influence its JV 
partners to sustain and enhance production in Nigeria; and statements regarding access to business opportunities 
in Africa Oil’s regions of focus and unlocking new sources of growth capit al. Such statements and information 
(together, "forward-looking statements") relate to future events or the Company's future performance, business 
prospects or opportunities. 
 
All statements other than statements of historical fact may be forward-looking statements. Statements concerning 
proven and probable reserves and resource estimates may also be deemed to constitute forward -looking 
statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be 
economically exploited. Any statements that express or involve discussions with respect to predictions, 
expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not 
always, using words or phrases  such as "seek", "anticipate", "plan", "continue", "estimate", "expect, "may", "will", 
"project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) 
are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve 
known and unknown risks, ongoing uncertainties and other factors that may cause actual results or events to differ 
materially from those anticipated in such forward -looking statements, inclu ding statements pertaining  to

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performance of commodity hedges,  uninsured risks, regulatory and fiscal changes, availability of materials and 
equipment, unanticipated environmental impacts on operations, duration of the drilling program, availability of third 
party service providers and defects in title , the sustainability of Africa Oil across oil and gas price cycles , the 
enhanced visibility and certainty over the use of capital , and statements regarding capital priorities .  Forward-
looking statements are based on a number of assumption s, including but not limited to, the ability of Africa Oil to 
delivery further growth, the ability to have a Board comprised at all times of a majority of independent non-executive 
directors, high value growth opportunities will continue to be funded, and the ability to access business opportunities 
in Africa Oil’s regions of focus.  No assurance can be given that these expectations will prove to be correct and 
such forward-looking statements should not be unduly relied upon. The Company does not intend, and  does not 
assume any obligation, to update these forward-looking statements, except as required by applicable laws. These 
forward-looking statements involve risks and uncertainties relating to, among other things, changes in macro -
economic conditions and t heir impact on operations, changes in oil prices, reservoir and production facility 
performance, contractual performance, results of exploration and development activities, cost overruns, uninsured 
risks, regulatory and fiscal changes including defects in title, claims and legal proceedings, availability of materials 
and equipment, availability of skilled personnel, the need to obtain required approvals from regulatory authorities, 
timeliness of government or other regulatory approvals, actual performance of facilities, joint venture partner 
underperformance, availability of financing on reasonable terms, availability of third party service providers, 
equipment and processes relative to specifications and expectations and unanticipated environmental, health and 
safety impacts on operations , satisfaction of the conditions to consummate the Proposed Reorganization; failure 
to complete the Proposed Reorganization; the amount of costs, fees, expenses and charges related to the 
Proposed Reorganization; and the failure to realize the anticipated benefits of the Proposed Reorganization. Actual 
results may differ materially from those expressed or implied by such forward-looking statements.

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REPORT TO  
SHAREHOLDERS
 
AFRICAOILCORP .COM
AFRICA OIL CORP.
FOR THE PERIOD ENDED MARCH 31, 2025

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PAGE 2
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
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.
“Africa Oil” , “AOC” , or 
the “Company” means Africa Oil Corp.
“Amalgamation 
Agreement”
means the definitive agreement between the Company, BTG Oil & Gas and BTG Holding the 
entity which holds the interests of BTG Oil & Gas in Prime, to reorganize and consolidate their 
respective 50:50 shareholdings in Prime.
“Applicable law” means all laws and regulations issued by authorities that have appropriate jurisdiction over the 
Company.
“Azinam” means Azinam Ltd.
B
“Bcf” means billion cubic feet.  
“Blocks” means blocks 2912 and 2913B.
“boepd” means barrels of oil equivalent per day.
“BTG Holding” means BTG Pactual Holding S.a.r.l.
“BTG Oil & Gas” means BTG Pactual Oil & Gas S.a.r.l.
C
“CGU”
means Cash Generating Unit. A Cash Generating Unit is defined as assets that are grouped 
together into the smallest group of assets that generates cash inflows from continuing use that 
are largely independent of the cash inflows of other assets or groups of assets.
“Chevron” means Chevron Corp.
“CIT” means Corporate Income Tax.
“Concessions” , “PSC” 
or “Production Sharing 
Contract”
means concessions, production sharing contracts and other similar agreements entered into 
with a host government providing for petroleum operations in a defined area and the division of 
petroleum production from the petroleum operations.
“Corporate Facility” means the $200.0 million facility dated October 20, 2022, with a three-year term, as amended 
from time to time. 
D
“DD&A” means Depreciation, Depletion and Amortization.
“DST” means Drill Stem Testing.
E
“EPS” means Early Production System. 
“EBITDAX” means Earnings Before Interest, Taxes, Depreciation & Impairment, Amortization and Exploration 
Expenses. 
“Eco”
means Eco (Atlantic) Oil & Gas Ltd, an international oil and gas exploration company that holds 
working interests in four exploration Blocks offshore Namibia and operates one exploration Block 
offshore South Africa and is party with the Company in Block 3B/4B, offshore South Africa and 
holds working interest in two exploration Blocks offshore Guyana.
“Entitlement 
production”
means production that is calculated using the economic interest methodology and includes cost 
oil, profit oil, tax oil and royalty oil.
“ESG” means Environmental, Social and Governance.
“ESHS” means Environmental, Social, Health and Safety.
“ESIA” means Environmental and Social Impact Assessment.
F
“FCF” means Free Cash Flow.
“FEED” means Front End Engineering and Design. 
“FID” means Final Investment Decision.
“FPSO” means Floating Production Storage and Offloading.
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.
GLOSSARY

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PAGE 3
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
J “J V ” means Joint Venture.
K “Kenya entities” means Centric Energy Kenya Limited, Africa Oil Kenya B.V Branch and Africa Oil Turkana Limited.
L
“LTI” means loss time injury. 
“LTIP” means Long Term Incentive Plan.
M
“Mcf” means million cubic feet. 
“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
“Petrovida” means PetroVida Holding B.V.
“PIA” means Petroleum Industry Act.
“PML” means Petroleum Mining Lease.
“PML 2” means the Petroleum Mining Lease containing the Akpo field.
“PML 3” means the Petroleum Mining Lease containing the Egina field.
“PML 4” means the Petroleum Mining Lease containing the Preowei field.
“PML 52” means the Petroleum Mining Lease containing the Agbami field.
“PPL” means Petroleum Prospecting License.
“PPL 261” means the Petroleum Prospecting License containing the South Egina prospect.
“PPT” means Profit Petroleum Tax.
“Prime” or “Prime Oil & 
Gas Coöperatief U.A.”
means Prime Oil & Gas Coöperatief U.A., previously known as Prime Oil & Gas B.V., a company 
that holds interests in     deepwater Nigeria production and development assets.
“PSA” means Petroleum Sharing Agreement.
“PSC” means Production Sharing Contract.
“PSU” means Performance Share Unit.
R
“RBL” means Reserves Based Lending.
“RSU” means Restricted Share Unit.
S “spud” or “spudded” means the initial drilling for an oil well.
T
“TotalEnergies” means TotalEnergies SE and subsidiaries. 
“TSX” means Toronto Stock Exchange.
U “US” means United States.
W
“WI”  means working interest.
“WI production”  means production based on the percentage of working interest owned.

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PAGE 4
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
MANAGEMENT’S DISCUSSION AND ANALYSIS
The Management’s Discussion and Analysis (“MD&A”) focuses on significant factors that have affected the Company during the three 
months ended March 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 unaudited interim condensed consolidated financial statements for the three months ended 
March 31, 2025, and 2024, and also should be read in conjunction with the audited consolidated financial statements for the years 
ended December 31, 2024, and 2023, and related notes thereto. 
The financial information in this MD&A is derived from the Company’s unaudited interim condensed consolidated financial statements 
which have been prepared in US dollars, in accordance with International Financial Reporting Standards as issued by the International 
Accounting Standards Board (“IFRS Accounting Standards”). 
This MD&A was reviewed and approved by the Board of Directors. The effective date of this MD&A is May 14, 2025. 
Additional information about the Company and its business activities is available on the Company’s website at www.africaoilcorp.com 
and on SEDAR at www.sedar.com.
PROFILE AND STRATEGY
Africa Oil 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 ‘AOI’. 
Africa Oil’s long-term objective is to implement a steady and predictable total shareholder returns model underpinned by an enhanced 
base dividend policy, whilst delivering organic growth from its core assets and pursuing disciplined inorganic growth opportunities 
focused on producing assets. This plan is supported by the Company’s high netback production assets in Nigeria that are included in its 
interests in Petroleum Mining Leases (“PMLs”) 2, 3, 4 and 52. These PMLs provide the Company with a long-life cash flowing asset base, 
to support its business objectives over the long term, and also present development opportunities for supporting future production. 
The Company’s other core assets are comprised of its Orange Basin opportunity set including Blocks 2912 and 2913B offshore Namibia 
and Block 3B/4B, offshore South Africa, as well as Equatorial Guinean exploration blocks (EG-18 and EG-31).
The Company is a unique investment opportunity, amongst its publicly-listed independent E&P peer group, for its Orange Basin 
opportunity set that includes an effective interest in the Venus light oil and associated gas discovery offshore Namibia. The Venus 
discovery, understood to be the largest oil discovery globally in 2022, has partially de-risked a new petroleum province in the Orange 
Basin that has significant prospectivity.

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

PAGE 5
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
HIGHLIGHTS AND OUTLOOK 
FIRST QUARTER 2025 AND POST PERIOD HIGHLIGHTS
• Closed the amalgamation transaction to take full control of Prime, doubling AOC’s reserves and production, and implemented a new 
policy to effectively triple dividend per share.
• During Q1 2025, (presented as if the amalgamation had closed on January 1, 2025):
 » Achieved average daily W.I. and entitlement production of 33,400 boepd and 37,700 boepd respectively, in line with expectations.
 » Sold five cargoes (approximately 5 MMbbl) at an average sales price of $79.5/bbl versus an average Dated Brent for the same 
period of $75.7/bbl;
 » Recorded cashflow from operations before working capital adjustment of $99.8 million. 
 » Received a distribution of $31.6 million from Impact.
 » Pro-actively reduced the RBL debt balance by $130.0 million to $620.0 million at the end of Q1 2025, reducing interest expenses.
 » End of Q1 2025 cash balance of $428.4 million, resulting in a net debt position of $191.6 million with a Net Debt/ EBITDAX of 
0.3x as at March 31, 2025.
• During Q1 2025 with the amalgamation closing on March 19, 2025, recorded net income of $50.9 million ($0.11 per share).
• Post end of Q1 2025:
 » Distributed the first quarterly cash dividend of approximately $25.0 million ($0.0371 per share) in April 2025.
 » AOC’s Board has declared the second quarterly dividend in 2025 of approximately $25.0 million ($0.0371 per share) payable in 
June 2025 to shareholders of record at the close of business on May 26, 2025.
 » The Company reduced the RBL debt balance by a further $80.0 million and has commenced the process to cancel its $65.0 
million Corporate Facility, which remains undrawn.
FINANCIAL SUMMARY (1)
Three months ended Year ended
Unit
March 31,  
2025
March 31,  
2024
December 31,  
2024
AOC highlights
Net income/ (loss) $’m 50.9 3.5 (279.1)
Net income/ (loss) per share – basic $/ share 0.11 (2) 0.01 (0.62)
Net debt position(3) $’m 191.6 285.9 289.1
WI production (3) boepd 33,400 34,200 34,000
Entitlement production (3) boepd 37,700 40,200 38,800
EBITDAX (4) $’m 141.6 n/a n/a
Cash flow from operations (4, 5) $’m 99.8 n/a n/a
Free Cash Flow (4) $’m 121.6 n/a n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on pages 14-16.
(2) Based on the Q1 2025 weighted average number of shares outstanding of 449,431,803 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 Prime to be comparable with 
March 31, 2025, net debt position and production numbers for the three months period ended March 31, 2025.  
(4) Highlights are reported for the year 2025 only as if the amalgamation had closed on January 1, 2025
(5) Cash flow from operations before working capital and interest payments.

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PAGE 6
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
HIGHLIGHTS AND OUTLOOK  - CONTINUED
OUTLOOK
Shareholder Returns
The first dividend under the Company’s enlarged base dividend policy of $25.0 million was paid during April 2025 and the Company’s 
Board has declared the second dividend in 2025 for distribution in June 2025, to shareholders of record at the close of business on 
May 26, 2025. 
The Company’s Board views the base annual distribution policy to be prudent with due consideration for its capital allocation options 
and the priority of maintaining a strong balance sheet in a range of market scenarios.
Nigeria
The Company remains focused on working with its JV partners to sustain and enhance production through targeted drilling and 
optimisation initiatives on its three producing fields in deepwater Nigeria.
At Egina, two producers were drilled in Q1 2025 with both expected to come onstream in Q2 2025. On Akpo, a well intervention and 
the drilling of one development well are planned for Q2 2025.  A  break to the rig campaign is planned from Q4 2025 to allow for 
interpretation of the available 4D seismic data and drilled well results to enable maturation of future infill drilling candidates.
The Company’s Nigerian portfolio includes infrastructure-led exploration assets that in case of commercial discovery success, could 
potentially present attractive short cycle, high return investment opportunities that would benefit from the existing facilities. One such 
opportunity, which is being progressed towards drilling is the Akpo Far East prospect  with an unrisked, best estimate, gross field 
prospective resource volume of 143.6 MMboe. The targeted hydrocarbons are predicted to be light, high gas-oil ratio (“GOR”) oil 
equivalent to those found in the Akpo field. If successful, initial production could be achieved from existing production manifolds with 
the potential to materially increase reserves on the Akpo Field. 
At Agbami, further planned maintenance including a full field shutdown in Q4 2025, is expected to support long-term performance 
with 4D seismic interpretation continuing in support of the upcoming drilling campaign. Rig and well long lead items contracting is 
underway, alongside the placement of orders for subsea trees, in preparation for the commencement of the infill drilling campaign in 
2027.
For Preowei, studies of the fast-track seismic data are continuing to further derisk the identified upside opportunities to enhance 
recoverable volumes. In parallel, the reengagement of the front-end engineering and design (“FEED”) contractor is planned in order 
to carry out additional evaluation aimed at optimizing the Preowei engineering, procurement, construction and installation (“EPCI”) 
phase costs.
Namibia Orange Basin Development and Exploration, Blocks 2912 and 2913B
The Venus Field is expected to be the first development area in Block 2913B. The Venus development plan is for up to 40 subsea wells 
tied back to a floating production, storage and offloading (“FPSO”) platform that can handle peak output of 160,000 barrels per day 
of oil. 
• Project preparation and decision-making – 
 » Front-End Engineering Designs (“FEED”): Q2 – Q4 2025
 » ESIA submission to authorities: Q4 2025
 » Final Investment Decision (“FID”) could be made during H1 2026 
The latest exploration drilling campaign was completed on April 25, 2025, with the drilling rig demobilized. The Company expects the 
next drilling campaign to commence during Q4 2025 and notes that TotalEnergies has publicly identified Olympe-1X, on Block 2912, 
as a possible target for this campaign.

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PAGE 7
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
HIGHLIGHTS AND OUTLOOK  - CONTINUED
South Africa Orange Basin, Block 3B/4B
Following the granting of an Environmental Authorization for exploration activities (drilling of up to 5 exploration wells) by the 
Department of Mineral Resources and Energy for the Republic of South Africa on September 16, 2024, the legislative notification and 
appeals process continues to progress with the relevant regulatory agencies. The operator has stated that with the approval process 
progressing the current plan is to drill the first exploration well on Block 3B/4B in 2026 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-1
The Company is in active dialogue with industry parties to attract farm in parties on both blocks, with the aspiration of completing the 
exercise by the end of Q3 2025.
If the Company is successful in attracting farminee partner(s) for these blocks, subject to customary consents and approvals including 
governmental and regulatory permissions, the Company anticipates that newly formed JVs could plan for exploration drilling in late 
2026 or during 2027. However, there is no guarantee the Company can secure farminee partners on acceptable terms and it does not 
intend to undertake exploration drilling on a sole risk basis if it is unsuccessful in its farm down campaign.
SUMMARY OF 2025 MANAGEMENT GUIDANCE AND ACTUALS
The Company’s full-year 2025 Management Guidance is unchanged and is repeated here for completeness. These estimates are based 
on a 2025 average Brent price of $75.0 per barrel. At an average Brent price of $85.0 per barrel the mid-point of the cash flow from 
operations guidance range is estimated to increase by approximately 19%, and at an average of $65.0 per barrel the mid-point is 
estimated to decrease by approximately 12%. 
2025 Guidance  Q1 2025 Actuals
WI production (kboepd) (1) 28.0 – 33.0 33.4
Entitlement production (kboepd) (2) 32.0 – 37.0 37.7
EBITDAX ($ million) (3) 500 - 600 141.6
Cash flow from operations ($ million) (3) 320 - 370 99.8
Capital investment ($ million) 150 - 190 28.2
(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 15 =====

PAGE 8
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
THE COMPANY’S SHAREHOLDING AND  
WORKING INTERESTS
The Company’s material interests and material exploration partnership interests as at March 31, 2025, are summarized in the following 
table:
Africa Oil’s Direct Working Interests (1,2)
Country Concession License renewal Working Interests
NIGERIA
PML 52 and PPL 2003(3) November 24, 2044
AOC
Chevron Corporation
Famfa Oil
8%
32%
60% (carried)
PML 2, 3, 4 and  
PPL 261 – PSA (4) May 24, 2043
AOC
TotalEnergies
SAPETRO
32%
48%
20% (carried)
SOUTH AFRICA Block 3B/4B October 26, 2024 (5)
AOC
TotalEnergies (Operator)
QatarEnergy
Azinam
Ricocure (Pty) Ltd
18% 
33%
24%
5.25%
19.75%
EQUATORIAL  
GUINEA
EG-18
EG-31
March 1, 2026
AOC (Operator)
GEPetrol
80%
20%
Africa Oil’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) The Company has agreed with its JV parties its withdrawal from the entirety of the production sharing contracts and joint operating 
agreements for Blocks 10BB, 13T and 10BA in Kenya with effect on and from June 30, 2023. The Company is waiting for government consent 
to complete its withdrawal and the transfer of rights and future obligations.
(3) Production currently from PML 52 and potential future production from PPL 2003 is covered by a PSA framework, in which Prime owns a 8% 
WI. 
(4) 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 Prime owns a 32% WI. Prime’s net WI in these assets is therefore 16%.
(5) The operator has submitted an application for license renewal. This is currently awaiting Government approval.
Information on the Company’s equity interests in Africa Energy and Impact is included in ‘Equity Investments in Associates’ on pages 
19-20.

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PAGE 9
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE
Macroeconomic conditions
International oil prices in Q1 2025 exhibited overall moderation where, after an initial surge in January, there was an extended decline 
followed by a recovery in March. The average Bloomberg Dated Brent was $75.7/bbl compared to the average of $74.7/bbl and  
$80.7/bbl observed in Q4 2024 and full year 2024 respectively. In Q1 2025, Bloomberg Dated Brent traded up to a high of $83.0/bbl 
and a low of $69.8/bbl.  
The price fluctuations in Q1 2025 were primarily due to underlying competing interactions between the global economic outlook 
and evolving supply dynamics. The uncertainty surrounding US tariffs resulted in concerns over economic slowdowns acting as a 
headwind for oil demand sentiment. This was compounded by OPEC+’s strategy of maintaining supply cuts being offset by increasing 
oil production from non-OPEC+ countries. 
The Middle East conflict and the associated Red Sea route disruptions persisted into the first quarter. However, its direct oil market 
impact appeared relatively contained by logistical rerouting and supply flexibility. The new US sanctions imposed on Iran and Venezuela 
also contributed to market tightness mitigating further price decline. 
Consequently, the current global market conditions and geopolitical risks continue to reinforce the attractiveness of potentially more 
secure supply from Atlantic basin sources, and West Africa in particular. 
Nigeria economic environment
Following the rebasing of the Consumer Price Index by the Nigerian National Bureau of Statistics, the headline inflation rate fell to 
24.8% in January 2025 from the previous record of 34.8% in December 2024. With the new 2024 base year, the upward inflation trend 
observed in 2024 appears to have been checked as the February and March inflation is given at 23.2% and 24.2%.  
In the first quarter, petrol and diesel prices experienced some reduction due to increase domestic supply primarily by the Dangote 
Refinery. Additionally, the exchange rate showed relative stability compared to Q4 2024. Notwithstanding, high transportation costs, 
insecurity and energy prices persist and remain the key drivers for high food costs as the effects of the 2023 fuel subsidy removal and 
foreign exchange market reform continue to be felt. Notably, the Central Bank of Nigeria reached the decision to maintain the current 
interest rate at 27.5% in line with its interventions in 2024. Despite these signs of stabilization, the outlook for the rest of 2025 will 
depend greatly on sustained policy implementation, security improvements and proper navigation of global economic uncertainties. 
Positively, Prime's Nigerian business activities continue to be minimally affected by domestic economic conditions, as its revenues are 
denominated in US Dollars. Moreover, the positioning of its producing assets in deepwater, offshore Nigeria effectively separates its 
operational environment from the security challenges encountered in the country's onshore areas.
SHAREHOLDER RETURNS
On March 20, 2025, the Company declared the first quarterly dividend of approximately $25.0 million or $0.0371 per share with 
payment during April 2025. The Company is pleased to announce that its Board has declared the distribution of the Company’s second 
2025 quarterly cash dividend of approximately $25.0 million or $0.0371 per share. This dividend will be payable on June 11, 2025, to 
shareholders of record at the close of business on May 26, 2025. 
This dividend qualifies as an ‘eligible dividend’ for Canadian income tax purposes. Dividends for shares traded on the Toronto Stock 
Exchange (“TSX”) will be paid in Canadian dollars on June 11, 2025; however, all US and foreign shareholders will receive USD funds. 
Dividends for shares traded on Nasdaq Stockholm will be paid in Swedish Krona in accordance with Euroclear principles on June 16, 
2025.
To execute the payment of the dividend, a temporary administrative cross border transfer closure will be applied by Euroclear from 
May 22, 2025, up to and including May 26, 2025, during which period shares of the Company cannot be transferred between the TSX 
and Nasdaq Stockholm. 
Payment to shareholders who are not residents of Canada will be net of any Canadian withholding taxes that may be applicable. For 
further details, please visit: https://africaoilcorp.com/investor-summary/total-shareholder-returns/. 
Future dividend declarations are subject to customary Board approval and consents.
Pursuant to the Company’s current Normal Course Issuer Bid (“NCIB”) share repurchase program that was launched on December 6, 
2024, Africa Oil is authorized to repurchase through the facilities of the TSX, Nasdaq Stockholm and/or alternative Canadian trading 
systems, as and when considered advisable by Africa Oil, up to 18,362,364 Common Shares of the Company, which represented 5% of 
its “public float” of 367,247,289 Common Shares as at November 22, 2024.
Purchases of Common Shares may occur over a period of up to twelve months commencing December 6, 2024, and ending on the 
earlier of December 5, 2025, the date on which the Company has purchased the maximum number of Common Shares permitted 
under the NCIB, and the date on which the NCIB is terminated by Africa Oil. 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 Africa Oil under the NCIB will 
be cancelled.

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PAGE 10
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
During Q1 2025, the Company repurchased a total of 5.9 million shares at an average price of C$1.94 per share. Since the launch of the 
current NCIB program, the Company has repurchased a total of 8.4 million shares at an average price of C$1.89 per share. 
In Canada, Bill C-59 sets out taxes on repurchases of equity, with a 2% tax applying to the net value of shares repurchased by any 
corporation resident in Canada whose shares are listed on a designated stock exchange. Bill C-59, was enacted on June 20, 2024, and 
the Company has paid the tax payable for shares purchased in 2024 and accrued for the tax payable on shares purchased during Q1 
2025. 
Group operations
On March 19, 2025, the Company completed the transaction with BTG Oil & Gas to consolidate its interest in Prime. The acquisition was 
completed by way of amalgamation whereby BTG Oil & Gas exchanged its 50 percent interest in Prime, held through its fully owned 
subsidiary BTG Pactual Holding S.à.r.l., in exchange for 239,828,655 newly issued shares in the Company. 
The production numbers included in the narrative discussion below include 100 percent of Prime 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 Year ended
Unit
March 31,  
2025
March 31,  
2024
December 31,  
2024
Total gross field production boepd 262,700 280,600 273,600
Average daily WI production (1) boepd 33,400 34,200 34,000
Average daily entitlement production boepd 37,700 40,200 38,800
Oil volumes sold MMbbl 5.0 2.0 9.0
Gas volumes sold bcf 5.0 4.0 17.4
Oil/gas percentage split % 75%/25% 81%/19% 77%/23%
(1) Production allocation occurs periodically and can result in a change in production numbers previously reported.
The total gross field production in Q1 2025 was lower than Q1 2024, primarily due to the expected natural reservoir decline across all 
assets. 
Performance across our deepwater portfolio remained robust in Q1 2025, with both Egina and Akpo fields delivering production ahead 
of expectations in the first quarter. At Akpo, the Akpo West wells continue to deliver above expectation supporting the continued 
strong performance and underpinning the consistency of the asset. On Egina, drilling operations resumed in January 2025, resulting 
in the successful completion of two new production wells, which are expected to come online in Q2 2025. Meanwhile, production 
at Agbami was temporarily impacted by scheduled compressor maintenance early in the quarter. These activities were executed as 
planned and are a key part of our strategy to safeguard long-term reliability and compression uptime on the asset.
Entitlement production is calculated using the economic interest methodology and includes cost oil, profit oil and royalty oil. It differs 
from WI production which is calculated based on field volumes multiplied by the Company’s effective WI in each Block. Aggregate oil 
equivalent production data comprises of light and medium crude oil and conventional natural gas production net to the Company’s 
WI in the Agbami, Akpo and Egina fields. These production rates only include sold gas volumes and not those volumes used for fuel, 
reinjected or flared.
In Q1 2025, Prime was allocated five oil liftings with a total sales volume of approximately 5.0 million barrels of oil at an average realized 
oil price of $79.5/bbl with one of these oil liftings occurring post amalgamation and therefore presented as revenue in the Company’s 
interim condensed consolidated statement of net income and comprehensive income. In Q1 2024, Prime was allocated two oil liftings 
with total sales volume of approximately 2.0 million barrels at an average realized oil price of $85.5/bbl. 
In 2024, Prime was allocated nine oil liftings with total sales volume of approximately 9.0 million barrels at an average realized oil price 
of $84.6/bbl.

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PAGE 11
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
FINANCIAL
Total revenues, cost of sales, gross profit, opex/boe, tax and net debt numbers included in the narrative discussion below include 100 
percent of Prime 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 Africa Oil accounting policies and presentation in the Company’s 
interim condensed consolidated statement of net income and comprehensive income 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 as if the amalgamation had closed on January 1, 2025. 
For this purpose, constructed Prime information to explain performance is included in the following tables to present on a consolidated 
basis net income for Q1 2025 and cash flow statement for Q1 2025 as if the amalgamation had closed on January 1, 2025, whereby the 
Africa Oil interim condensed consolidated statement of net income and comprehensive income and the Africa Oil interim condensed 
consolidated statement of cash flows for Q1 2025 are combined with the Prime statement of net income and comprehensive income 
and the Prime statement of cash flows for the period until March 19, 2025. Adjustments are included to conform Prime financial 
information with Africa Oil accounting policies and for any transactions between Africa Oil and Prime prior to amalgamation for the 
purpose of presenting constructed Prime information to explain performance.
 
Constructed Prime information for purposes of explaining performance
Interim condensed consolidated statement of net income
For the three months ended
AOC Q1 2025 
per Financial 
Statements
Prime for period 
from January 1, 
2025, to March 
19, 2025 Adjustments (1)
March 31,  
2025
Revenue 76.4 323.5 - 399.9
Cost of Sales 
Production costs (51.2) (187.4) 2.0 (236.6)
Depletion and decommissioning costs (12.1) (71.3) - (83.4)
(63.3) (258.7) 2.0 (320.0)
Gross profit 13.1 64.8 2.0 79.9
General and administrative expenses (13.5) (6.2) - (19.7)
Operating (loss)/ profit (0.4) 58.6 2.0 60.2
Finance income 1.1 2.4 - 3.5
Finance expense (2.8) (21.3) - (24.1)
Net financial items (1.7) (18.9) - (20.6)
Share of profit from investment in joint venture 15.9 - (15.9) -
Share of loss from investments in associates (2.0) - - (2.0)
Reversal of impairment of investment in joint venture 42.9 - (42.9) -
Profit before tax 54.7 39.7 (56.8) 37.6
Income tax (3.8) (7.9) - (11.7)
Net income attributable to common shareholders 50.9 31.8 (56.8) 25.9
(1) Adjustments to remove items related to Prime as fully consolidated above.

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PAGE 12
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
Interim condensed consolidated statement of cash flows
For the three months ended
AOC Q1 2025 
per Financial 
Statements
Prime for period 
from January 1, 
2025, to March 
19, 2025 Adjustments (1)
March 31,  
2025
Operations
Profit before tax 54.7 39.7 (56.8) 37.6
Adjustments as per financial statements (55.6) 59.0 58.8 62.2
Net cash (used)/ generated in operating activities 
before working capital (0.9) 98.7 2.0 99.8
Changes in working capital 37.3 (25.7) - 11.6
Net cash generated in operating activities 36.4 73.0 2.0 111.4
Investing
Expenditures on oil and gas properties (3.6) (22.6) (2.0) (28.2)
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 0.9 2.2 - 3.1
Cash acquired from Prime consolidation (2) 380.4 - (381.3) (0.9)
Net cash generated/ (used) in investing activities 473.8 (20.4) (443.3) 10.1
Financing
Repayment RBL Facility (130.0) - - (130.0)
Repayment of principal portion of lease commitments (0.1) - - (0.1)
Dividends paid to shareholders - (120.0) 120.0 -
Repurchase of share capital (8.3) - - (8.3)
Interest expense paid (4.9) (10.8) - (15.7)
Net cash used in financing activities (143.3) (130.8) 120.0 (154.1)
Foreign exchange variation on cash and cash 
equivalents 0.1 - - 0.1
Total cash flow 367.0 (78.2) (321.3) (32.5)
Cash and cash equivalents, beginning of the period 61.4 399.5 - 460.9
Cash and cash equivalents, end of the period 428.4 321.3 (321.3) 428.4
(1) Adjustments to remove items related to Prime as Prime fully consolidated above 
(2) Reflects impact of net cash movement on the level of BTG Pactual Holding S.à.r.l.

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PAGE 13
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
Financial Metrics(1)
Three months ended Year ended
Unit
March 31,  
2025
March 31,  
2024
December 31,  
2024
Total revenues $’m 399.9 176.6 782.7
Cost of Sales (2) $’m 320.0 80.0 428.2
Gross profit $’m 77.9 96.6 354.5
Opex/boe (3,4) $/boe 13.4 10.4 10.3
Cash flow from operations before working capital $’m 99.8 n/a n/a
Cash flow from operations $’m 111.4 n/a n/a
Free cash flow $’m 121.6 n/a n/a
Free cash flow/boe (4) $/boe 35.8 n/a n/a
Tax $’m 11.7 21.2 120.5
Capex $’m 28.2 n/a n/a
Net Debt $’m 191.6 285.9 289.1
EBITDAX $’m 141.6 n/a n/a
Net Debt/EBITDAX (5) ratio 0.3 n/a n/a
(1) The table includes non-GAAP measures. Definitions and reconciliations to these non-GAAP measures are provided on pages 14-16.
(2) Given the nature of Prime’s operations in terms of oil cargo liftings and the variability in their frequency from one quarter to next, the non-cash 
accounting treatment of underlift/overlift and the timing between recording revenues and receipts of sales cash, leads to high variability in 
quarterly financial metrics. Please refer to the commentary in the rest of this section for the specific details of this period’s changes relative to 
the corresponding historical period.   
(3) Opex represents direct production costs.
(4) Boe is calculated on an entitlement basis. 
(5) Calculated based on Q1 2025 EBITDAX multiplied by 4.
Total revenues
Three months ended Year ended
Unit
March 31,  
2025
March 31,  
2024
December 31,  
2024
Oil revenue $’m 394.5 171.0 762.2
Gas revenue $’m 5.4 5.6 20.5
Total revenue $’m 399.9 176.6 782.7
Realized oil prices (1) $/bbl 79.5 85.5 84.6
Oil volumes sold MMbbl 5.0 2.0 9.0
Realized gas prices $/bcf 1.1 1.4 1.2
Gas volumes sold Bcf 5.0 4.0 17.4
(1) Realized oil prices might be different to values calculated from the table above due to roundings. 
The increase in oil revenue in Q1 2025 was mainly driven by higher liftings compared to Q1 2024 as cargoes initially scheduled to be 
lifted during Q4 2024 were pushed into Q1 2025 resulting in 5 cargo liftings in Q1 2025.

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PAGE 14
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
Cost of sales
Three months ended Year ended
$’m
March 31,  
2025
March 31,  
2024
December 31,  
2024
Depletion costs 83.4 96.7 372.0
Cost of operations 45.6 37.3 146.1
Movements on overlift/ underlift balances 175.0 (76.2) (171.2)
Royalties – oil and gas 13.2 19.0 70.2
Others 2.8 3.2 11.1
Total cost of sales 320.0 80.0 428.2
Cost of sales increased in Q1 2025 compared to Q1 2024. The increase in costs of sales is mainly driven by a large overlift movement in 
Q1 2025 to unwind a large underlift position that existed as per end 2024, compared to an underlift movement in Q1 2024.  
Costs of operations increased in Q1 2025 compared to Q1 2024, mainly driven planned maintenance costs and other repairs not 
incurred in Q1 2024.
Other costs of sales relates to sales costs and the NDDC Levy, which concerns the Niger Delta Development Commission Levy imposed 
to fund the sustainable development of the Niger Delta region. 
Opex/boe
Opex/boe is a non-GAAP measure which represents production costs on a per barrel of oil equivalent basis (using entitlement 
production). This allows the Company to better analyze performance against prior periods on a comparable basis. The most direct 
financial statement measure is production costs. Entitlement production is calculated using the economic interest methodology and 
includes cost oil, profit oil and royalty oil and is different from WI production that is calculated based on project volumes multiplied by 
the effective WI in each Block.
Three months ended Year ended
Unit
March 31,  
2025
March 31,  
2024
December 31,  
2024
Cost of operations $’m 45.6 37.3 146.1
Entitlement production MMboe 3.4 3.6 14.2
Opex/boe $/boe 13.4 10.4 10.3
Opex/boe increased in Q1 2025 compared to Q1 2024 primarily from the higher cost of operations and slightly lower entitlement 
production. 
Entitlement production is used as the denominator as production costs include carry of costs that are recovered through entitlement 
production.
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 Year ended
$’m
March 31,  
2025 (1)
March 31,  
2024 (1)
December 31,  
2024 (1)
Cash flow from operations 111.4 n/a n/a
Working capital adjustments included in cash flow  
from operations (11.6) n/a n/a
Cash flow from operations before working capital 99.8 n/a n/a
(1) Cash flow from operations has been reported for the year 2025 only as if the amalgamation had closed on January 1, 2025.

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

PAGE 15
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
Free cash flow and Free cash flow/boe (1)
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 Year ended
Unit
March 31,  
2025 (1)
March 31,  
2024 (1)
December 31,  
2024 (1)
Total cash flow $’m (32.5) n/a n/a
Add back repurchase of share capital $’m 8.3 n/a n/a
Add back debt service costs (2) $’m 145.8 n/a n/a
Free cash flow $’m 121.6 n/a n/a
Entitlement production MMboe 3.4 n/a n/a
Free cash flow/boe $/boe 35.8 n/a n/a
(1) Free cash flow and Free cash flow/boe have been reported for the year 2025 only as if the amalgamation had closed on January 1, 2025.  
(2) Debt service costs comprise interest payments, repayments and drawdowns of third-party borrowings. 
Tax
The tax expense is made up of the following items:
Three months ended Year ended
$’m
March 31,  
2025
March 31,  
2024
December 31,  
2024
Deferred income tax (34.3) (16.0) (80.9)
Education tax 1.5 3.5 14.2
Corporate income tax 26.5 31.3 130.1
Withholding tax on dividends 18.0 - 22.5
Capital gains tax - - 33.0
Petroleum Profit Tax - - (2.3)
Other taxes - 2.4 3.9
Total tax 11.7 21.2 120.5
The tax charge was lower in Q1 2025 compared to Q1 2024 mainly driven by a higher deferred income tax credit following completion 
of the amalgamation. 
Education tax is imposed on every Nigerian company at a rate of 3.0% of the assessable profit 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 PSA 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.

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PAGE 16
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
Capital expenditure
Capital expenditure is made up of the following items:
Three months ended Year ended
$’m
March 31,  
2025 (1)
March 31,  
2024 (1)
December 31,  
2024 (1)
Nigeria 26.4 n/a n/a
Equatorial Guinea 1.7 n/a n/a
South Africa 0.1 n/a n/a
Total capex 28.2 n/a n/a
(1) Capital expenditure has been reported for the year 2025 only as if the amalgamation had closed on January 1, 2025.  
Capital expenditure in Q1 2025 in Nigeria mainly related to infill drilling on Egina plus some minor facilities costs. 
Net Debt
Net Debt is a non-GAAP measure. Net Debt is calculated as loans and borrowings less cash and cash equivalents.
Three months ended Year ended
As at/ $’m
March 31,  
2025
March 31,  
2024
December 31,  
2024
Loans and borrowings 620.0 750.0 750.0
Cash and cash equivalents (428.4) (464.1) (460.9)
Net Debt 191.6 285.9 289.1
As at March 31, 2025, the Company has $428.4 million of cash and cash equivalents and $620.0 million of debt (as at December 31, 
2024 - $460.9 million of cash and cash equivalents and $750.0 million of debt). During Q1 2025, the Company pro-actively repaid 
$130.0 million under its RBL facility reducing outstanding debt to $620.0 million. 
EBITDAX and Net Debt/EBITDAX
EBITDAX is a non-GAAP measure. This is used as a performance measure to understand the financial performance from the Company’s 
business operations without including the effects of the capital structure, tax rates, DD&A and impairment expenses. A reconciliation 
from total profit (a GAAP measure) to EBITDAX (a non-GAAP measure) is shown below.
Net Debt/EBITDAX is a non-GAAP measure. Net Debt divided by EBITDAX is a measure of the leverage.
Three months ended Twelve months ended
$’m
March 31,  
2025 (1)
March 31,  
2024 (1)
March 31,  
2025 (1)
Total profit/ (loss) 25.9 n/a n/a
Add back:
Tax 11.7 n/a n/a
Finance costs 24.1 n/a n/a
Finance income (3.5) n/a n/a
Depletion costs 83.4 n/a n/a
Exploration expenses - n/a n/a
EBITDAX 141.6 n/a n/a
Net Debt 191.6
Net Debt/EBITDAX 0.3
(1) EBITDAX and Net Debt/EBITDAX have been reported for the year 2025 only as if the amalgamation had closed on January 1, 2025.  
(2) Net debt/EBITDAX has been calculated based on extrapolating Q1 2025 EBITDAX to a full year EBITDAX number.

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

PAGE 17
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
Crude Oil Marketing
In considering cargo liftings, the reader should note that the timing and the frequency of these can vary based on a number of factors 
such as: reservoir performance; actual realized oil price; capex; opex; underlift/overlift positions and marine logistics. The revenue 
numbers reported include cost oil, profit oil and royalty oil where relevant for each field.
The Group uses a mix of financial derivatives and physical forward sales contracts to manage its commodity price risk and ensure 
stability in cash flows. Its strategy is to hedge approximately 50-70% of its next 12-months’ scheduled cargos. 
In most of the Group’s oil offtake contracts, the Dated Brent component of the forward price at the time of entering the contract is not 
fixed but determined on or around the date of the lifting for spot cargos either on an average monthly basis, 5-days after bill of lading 
date or similar pricing mechanism. If the Group wants to utilize the oil offtake contract for commodity risk management, it can either fix 
the Dated Brent component or utilize a trigger pricing mechanism. For the trigger pricing mechanism, when the forward price curve 
falls below a certain trigger price for a certain month, this mechanism provides an irrevocable instruction to an off-taker to fix the Dated 
Brent price component of a cargo. The trigger price is based on a percentage of the Brent forward curve at the time the instruction was 
given for the month of the expected lifting. If the forward price curve does not fall below that threshold, the respective cargo is sold at 
spot.
The average cargo size lifted is one million barrels of oil. 
Oil sales were comprised of the following: 
Three months ended Year ended
Oil Sales Unit
March 31,  
2025
March 31,  
2024
December 31,  
2024
Number of cargo liftings 5 2 9
Of which:
Sold forward with a fixed Dated Brent 2 - 2
Sold at spot 3 2 7
5 2 9
Gross crude oil sales
Quantity in Mboe Mboe 4,960.0 2,000.6 9,012.8
Average sales price $/bbl 79.5 85.5 84.6
Average Bloomberg Dated Brent for 
the period $/bbl 75.7 83.1 82.7
 
Prime sold 5 cargoes during Q1 2025 at an average price of $79.5/bbl with one of these cargoes sold post amalgamation and therefore 
presented as revenue in the Company’s interim condensed consolidated statement of net income and comprehensive income. Of the 
7 cargoes expected for the remainder of the year post Q1 2025, 4 cargos had the trigger price mechanism activated in April 2025 at an 
average price of $64.5/bbl. The remaining 3 cargoes are currently unhedged with no trigger price mechanism in place. 
The combination of achieved sales prices in Q1 2025 and future fixed prices have materially de-risked the impact of oil price volatility 
on the business for 2025. For example, assuming a flat price of $50/bbl Dated Brent across Q2-Q4 2025, the average realized sales 
price for 2025 will be approximately $67/bbl.
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. All three producing 
fields have high quality reservoirs and produce light to medium sweet crude oil through FPSO facilities. Akpo and Egina also export 
associated gas which feeds into the Nigerian liquified natural gas plant, whilst Agbami associated gas is mostly reinjected.

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

PAGE 18
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
The three fields produce through subsea infrastructure of wells, manifolds and flowlines connected to three purpose built FPSOs. 
Water injection is used in all fields to maintain reservoir pressure and improve reservoir recoveries, and dedicated water injection wells 
are positioned to support the producing wells. The produced oil is sold and transported to the international markets directly from the 
offshore field locations. 
The Company has near-field exploration opportunities, including the Akpo Far East prospect, which is located to the east and downdip 
from the Akpo field on the PML 2 concession area. The trap is defined by dip closure to the south and east, with stratigraphic trapping 
to the northwest. The reservoir comprises Miocene aged ‘G Sands’ that form turbiditic deep water fan lobes, equivalent to the G Sands 
in production in the Akpo main field. 
Work is progressing towards the drilling of an exploration well targeting an unrisked, best estimate, gross field prospective resource 
volume of 143.6 MMboe, at an estimated gross field cost of approximately $50 million. 
The key risk for the prospect is up dip stratigraphic seal, which requires an avulsion channel to separate Akpo Far East from the 
main Akpo field. This sealing facies component may be compromised by a set of later channels that cut across the avulsion channel. 
Furthermore, the prospect is assumed to hold a hydrocarbon column of approximately 500 m, which is approximately 350 m greater 
than the column observed for the G Sands in the Akpo field. The prospect is supported by seismic AVO1 analysis with the G Sands in 
the prospect having a similar seismic response to those in the field and having an apparent cut-off at 4,600m TVDss, which is assumed 
to be the oil-water-contact. 
The targeted hydrocarbons are predicted to be light, high GOR oil equivalent to those found in the Akpo field.
Please refer to pages 19-20 of the Company’s Annual Information Form for the Year Ended December 31, 2024, for the detailed 
commercial information, and pages 41–50 of the same document for the detailed technical information.
Block 3B/4B – South Africa 
Africa Oil holds an 18.0% interest in Block 3B/4B following the completion of the agreement with Eco to acquire an additional 1.0% 
(one percent) interest from Azinam Limited, Eco’s wholly owned subsidiary, in exchange for all common shares and warrants held by 
the Company in Eco. Africa Oil will continue to benefit from the carry agreed between Eco, TotalEnergies and QatarEnergy prior to the 
transfer of the interest to Africa Oil.
On August 28, 2024, the Company announced the completion of the strategic farm down agreement with TotalEnergies and QatarEnergy. 
The Company retained a direct 17.0% (increased to 18.0% in Q1 2025) non-operated interest in the block and operatorship was 
transferred to TotalEnergies. 
Transaction highlights are:
• Maximum transaction value of up to $46.8 million to the Company. 
• The Company will receive, subject to achieving certain milestones defined in the farm down agreement, staged payments for a total 
cash amount of $10.0 million, of which $3.3 million was received at completion with the remaining balance to be received in two 
successive payments conditional upon achieving key operational and regulatory milestones.
• The Company will also receive a full carry of its retained share of all JV costs, up to a cap, that is repayable to TotalEnergies and 
QatarEnergy from production, and which is expected to be adequate to fund the Company’s share of drilling for 1-2 wells on the 
license.
The Company expects that the first exploration well on Block 3B/4B can be drilled during 2026.
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. GEPetrol, the national oil company of Equatorial Guinea, holds the balance in each block and is carried during the 
exploration phase. Work programs on both Blocks include re-processing of existing 3D seismic surveys and identification of prospects 
within the first 2-year sub period. A 1-year extension of the first Exploration sub-period was granted on December 23, 2024, extending 
the renewal period to March 1, 2026. At the end of Q1 2025, all financial commitments for the initial exploration period have been met, 
the 1-year extension should enable the required technical work to be completed.
These blocks present two distinct exploration strategies with EG-31 being infrastructure-led, targeting natural gas prospects in proximity 
to gas transportation, processing and export infrastructure, and EG-18 being a frontier exploration play targeting a deepwater oil 
prospect with multi-billion barrel potential.

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PAGE 19
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
BUSINESS UPDATE - CONTINUED
Equity Investments in Associates
As at March 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 March 31, 2025:
Africa Energy Impact (1)
Issued and Outstanding 2,395,812,249 1,139,147,442
Shares held by AOC at December 31, 2024 276,982,414 449,464,396
Shares acquired in the period - -
Shares held by AOC at March 31, 2025 276,982,414 449,464,396
AOC’s holding (%) – March 31, 2025 11.56% 39.46%
AOC’s holding (%) – December 31 2024 19.67% 39.46%
Share price (CAD) on March 31, 2025 0.04 -
Exchange rate to USD on March 31, 2025 0.70 -
(1) Impact is a privately held UK company and no share price is available.
Impact
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. 
Impact is a private UK oil and gas exploration company with assets located offshore Namibia and South Africa. 
In 2024, the Company acquired an additional 105.9 million shares in Impact for $88.6 million, across two transactions, increasing its 
interest from 31.1% to 39.5%. This enhances the Company’s strategic position, rights and influence over a core asset and value driver 
for the Company.
On November 1, 2024, the Company announced the completion of a strategic farm-down agreement between its investee company, 
Impact, and TotalEnergies. Following the closing of this deal, Impact retains a 9.5% interest in the Blocks that is fully carried for all joint 
venture costs, with no cap, through to first commercial production. Impact also received a cash reimbursement of approximately $99.2 
million for its share of the past costs incurred on the Blocks net to the farmout interest. Following this, in Q1 2025 the Company received 
a distribution of $31.6 million from Impact.
This agreement provides Impact with a full interest-free carry loan over all of Impact’s remaining development, appraisal and exploration 
costs on the Blocks from January 1, 2024 (“Effective Date”), until the date on which Impact receives the first sales proceeds from oil 
production on the Blocks (“First Oil Date”).
On and from the First Oil Date, the carry is repayable to TotalEnergies in kind from 60% of Impact’s after-tax cash flow net of all joint 
venture costs, including capital expenditures. During the repayment of the carry, Impact will pool its entitlement barrels with those of 
TotalEnergies for more regular off-takes and a more stable cashflow profile and will also benefit from TotalEnergies’ marketing and sales 
capabilities.
Since the initial Venus-1X oil discovery in February 2022, four appraisal wells have been drilled to assess the Venus Field in Block 
2913B, offshore Namibia. Development studies are ongoing, with a final investment decision targeted by mid-2026. The Venus Field is 
expected to produce approximately 150 kbopd of ~45° API oil.
Also in 2024, two additional 3D seismic surveys were completed across the blocks, resulting in most of the licensed area now being 
covered. This data is currently being processed and interpreted and will help further evaluate prospects and leads in the far northern 
and southern parts of the Blocks. 
During Q1 2025, the joint venture completed the drilling of Tamboti-1X exploration well in Block 2913B.  Tamboti-1X was safely 
and successfully drilled to a total depth of 6,450mMD on Block 2913B, approximately 12km northeast of the Mangetti-1X well and 
approximately 25km north-northwest of the Venus-2A well, using the Deepsea Mira semi-submersible drilling rig. Black oil was 
encountered within 85m of net reservoir of lower quality Upper Cretaceous sandstones, belonging to the Mangetti fan system. A DST 
program was completed at the Tamboti-1X location, and results from the acquired log, core and DST data are currently under analysis.
On April 28, 2025, the Company announced the result of the Marula-1X exploration well on Block 2913B. The well was safely drilled 
to a total depth of 6,460m (measured depth) on block 2913B, targeting Albian aged sandstones, within the Marula fan complex, 
approximately 47 Km south of the Venus-1X well, using the Deepsea Mira semi-submersible drilling rig. No hydrocarbons were 
encountered in the primary target in the Marula-1X well and no Drill Stem Test was performed. A comprehensive analysis of the well 
results is now underway.

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PAGE 20
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
Africa Energy
Africa Energy is a TSX-Venture (Toronto) and Nasdaq First North Growth Market (Stockholm) listed international oil and gas exploration 
company with an interest in Block 11B/12B offshore South Africa. There are two gas condensate discoveries (Brulpadda and Luiperd) 
on this block in proximity to offshore gas infrastructure and onshore gas market in Mossel Bay, South Africa.
On July 1, 2024, Africa Energy announced that CNR International (South Africa) Limited, a partner in Block 11B/12B, has provided 
notice to the joint venture partners that it will withdraw from its 20% interest in the Block. On July 29, 2024, TotalEnergies EP South Africa 
B.V., the operating partner on the Block, and QatarEnergy International E&P LLC announced that they will withdraw from their 45% 
and 25% operated interests in the Block, respectively. Under the joint operating agreement, the withdrawing parties will assign their 
interest free of charge to Main Street 1549 Proprietary Ltd. (“Main Street”), the non-withdrawing partner, which currently has a direct 
10% participating interest in Block 11B/12B.
Africa Energy owns 49% of the common shares and 100% of the Class B shares of Main Street. The remaining 51% of the common 
shares of Main Street are held by Arostyle. In light of the withdrawal of the joint venture partners in Block 11B/12B, and subject to all 
relevant regulatory approvals, Main Street expects to hold a 100% participating interest in Block 11B/12B.
On December 20, 2024, Africa Energy announced that it has entered into a non-binding agreement with Arostyle Investments (RF) 
Proprietary Ltd. (“Arostyle”), to restructure their joint investment in Main Street. Under the non-binding agreement, Africa Energy and 
Arostyle agreed that subject to all relevant regulatory approvals, the Parties will restructure Main Street resulting in the Company holding 
a direct 75% participating interest and Arostyle holding a direct 25% participating interest in Block 11B/12B, with the relationship 
between the Parties being governed by the existing Joint Operating Agreement in respect to Block 11B/12B.
Africa Energy and Arostyle believe that natural gas will play a critical role in South Africa’s energy transition, and the use of indigenous 
gas from Block 11B/12B discoveries are currently the most material domestic supply option in South Africa. 
On March 31, 2025, Africa Energy announced the closing of a private placement of common shares, including the issue of common 
shares for debt. Africa Oil did not participate in this private placement and as a result its shareholding in Africa Energy has been 
reduced from 19.67% as at December 31, 2024, to 11.56% as at the date hereof. Some of the proceeds from the private placement 
were used to repay Africa Oil’s debt of approximately $4.5 million.  
ENVIRONMENTAL, SOCIAL AND GOVERNANCE 
The Company is committed to operating in a responsible manner that integrates sustainability considerations throughout its decision-
making and operational management, to support Company commercial objectives. The Company is focused on the effective 
identification and management of risk in its operational activities and, to the extent that it is reasonably able to influence them, those 
of its JV parties and investee companies. The Company selects its operating parties in part on their ability and commitment to manage 
ESG risks effectively. The Company monitors operator performance and works with operators where possible and necessary to improve 
performance. The Company’s role as the custodian of its shareholders’ capital is to ensure robust governance systems are in place to 
minimize risks and deliver our sustainability goals.
As part of those governance systems, the Company receives operator ESG performance data from Nigeria on a quarterly basis, which 
allows it to monitor alignment with agreed ESG targets and objectives. Prior to the amalgamation, at the Company’s request, Prime 
developed an updated ESG Strategy and GHG Roadmap in 2024, focused on compliance with IFC Performance Standards, a long term 
plan for net zero Scope 1 and 2 GHG emissions by 2050 and zero routine flaring by 2030. The Company will continue to implement 
this plan. 
Reductions in flaring and fugitive emissions will support the Company’s objectives to reduce working interest scope 1 greenhouse gas 
(“GHG”) emissions by 25% by 2025 and by 35% by 2030 compared to a 2020 baseline as part of Prime’s Net Zero by 2050 for scope 1 
and 2 emissions. 
Additionally, the Company will continue Prime’s engagement of independent Environmental, Social, Health and Safety (“ESHS”) 
monitoring reviews conducted annually to support the Company’s reserves-based lending facility. The 2024 Monitoring Review found 
that overall, Prime was managing the ESHS aspects of its business, in its non-operated role, “exceptionally well,” with no significant 
issues that would impact financing. A 2025 monitoring review for the Company is currently being undertaken.
The Company has completed an environmental and social impact assessment to support permitting and licensing to support exploration 
drilling activities in Block 3B/4B in South Africa. The Company submitted an ESIA application for proposed drilling activities on Block 
3B/4B during Q2 2024. An Environmental Authorization was issued by the regulator in September 2024 and that is being followed by 
a stakeholder consultation and appeals process which concluded in December 2024. Operatorship has been transferred to TEEPSA. 
The regulator is expected to provide its final decision on the appeals during mid-2025.
As part of its compliance with its PSC requirements in Equatorial Guinea and in line with the Company’s Social Investment Framework, 
the Company has funded the renovation of a school at Ayene in mainland Equatorial Guinea. In addition to the PSC requirements, 
Africa Oil funded school supplies for all students and classrooms at the recently renovated school.
For the Venus project in Namibia, the Operator has completed geophysical and geotechnical surveys and has commenced the 
development of an ESIA to support permit approvals for the construction and operation of the project. A draft Scoping Report for the 
Venus Project in Namibia has been issued on behalf of the Operator, the final version which will be submitted to the Ministry of Mines 
and Energy: Directorate of Petroleum Affairs (MME) for review. The recommendation of the MME will be submitted to the Ministry of 
Environment, Forestry and Tourism: Directorate of Environmental Affairs (MEFT) for final decision-making and acceptance.
BUSINESS UPDATE - CONTINUED

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PAGE 21
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
The Company’s environmental and social management system, which is overseen by the Board-level Sustainability Committee, aims 
effectively and appropriately to identify, monitor and address environmental, health & safety and social risks to our business and 
investments, in addition to identifying opportunities for performance improvement and risk reduction. The Company maintains a risk 
register by which it monitors financial, operational and ESG risks to the Company. Africa Oil regularly undertakes annual independent 
HSEC audits and engages with a range of ESG ratings assessments in support of investor and broader stakeholder engagement, as well 
as to identify opportunities for performance improvement.
Africa Oil is committed to regular review and update of its sustainability strategy to ensure continued alignment with both the Company’s 
evolving business and the broader global context. 
The Company was awarded a silver rating by the ESG rating agency EcoVadis in April 2025.  The independent evaluation undertaken 
concluded that the Company was within the top 10% of all companies evaluated for ESG performance. 
To the extent possible given its non-Operator role on assets, the Company endeavors to undertake its activities in line with the IFC’s 
Performance Standards on Environmental and Social Sustainability and independent monitoring reviews are conducted on a regular 
basis to assess compliance with those standards. The most recent review was completed in December 2024.  This found that Company 
management systems were fit for purpose to manage ESG risks. The report is published, along with all other Independent Monitoring 
Group reports, on Africa Oil’s website. 
The Company’s 2024 Sustainability Report, published on May 12, 2025, is disclosed on the Company website, as in previous reports it 
contains more detailed information on our performance and strategy.
On an ongoing basis, the Company monitors the development of applicable legislation to ensure compliance with evolving policy 
and associated regulatory requirements. As the Company has a primary listing in Canada on the Toronto Stock Exchange and a 
secondary listing in Sweden on the Oslo Stock Exchange, this includes sustainability disclosure requirements in both Canada and the 
EU, including the EU Corporate Sustainability Reporting Directive (CSRD). The Company takes note of recent proposals by the EU to 
reduce significantly the reporting requirements under CSRD.
SUMMARY OF QUARTERLY INFORMATION
All financial information included in the narrative discussion below is based on the consolidated statement of net income and 
comprehensive income 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-Mar 
2025
31-Dec 
2024
30-Sep 
2024
30-Jun 
2024
31-Mar 
2024
31-Dec 
2023
30-Sep 
2023
30-Jun 
2023
Revenue 76.4 - - - - - - -
Net income/ (loss) attributable to 
common shareholders ($’m) 50.9 6.2 (289.2) 0.4 3.5 (88.8) 47.1 106.9
Weighted average shares  
– Basic ‘000 468,472 442,690 442,960 451,231 460,991 462,231 462,340 456,229
Weighted average shares  
– Diluted ‘000 476,836 449,667 442,960 464,890 474,746 472,942 473,959 467,839
Basic income / (loss) per share ($) 0.11 0.02 (0.65) 0.00 0.01 (0.19) 0.10 0.23
Diluted income/ (loss) per share ($) 0.11 0.02 (0.65) 0.00 0.01 (0.19) 0.10 0.23
SUMMARY OF KEY ITEMS OF FINANCIAL PERFORMANCE IN THE THREE MONTHS ENDED MARCH 31, 
2025, AND MARCH 31, 2024
Three months ended
March 31,  
2025
March 31,  
2024
 Revenue 76.4 -
 Gross Profit 13.1 -
 General and administrative expenses (13.5) (5.1)
 Net income 50.9 3.5
 Adjusted net income 10.0 17.8

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PAGE 22
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
Revenue
Revenue generated in Q1 2025 was $76.4 million (Q1 2024 – nil) and relates to 1 cargo sold post amalgamation at a price of $74.2/bbl. 
Prior to the closing of the amalgamation on March 19, 2025, the Company did not report any revenue in its consolidated statement of 
net income and comprehensive income.
Gross profit
Gross profit reported in Q1 2025 was $13.1 million (Q1 2024 – nil). Gross profit was impacted by costs of sales in Q1 2025 of $63.3 
million (Q1 2024 – nil) and mainly comprised of depletion costs of $12.1 million, movements on overlift/underlift balances of $41.9 
million and costs of operations of $7.4 million. 
General and administrative costs 
On March 19, 2025, the Company announced the completion of the amalgamation to acquire the remaining 50% interest in Prime in 
exchange for 239,828,655 newly issued common shares in Africa Oil. 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
March 31,  
2025
March 31,  
2024
 General and administrative expenses 13.5 5.1
 BTG Oil & Gas transaction related expenses (7.6) (0.3)
 Adjusted general and administrative expenses 5.9 4.8
 
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, amounted to $5.9 million in Q1 2025 (Q1 2024 - $4.8 million). Share-
based compensation charges not impacted by the closing of the amalgamation amounted to $1.2 million in Q1 2025 (Q1 2024 – $0.5 
million) are impacted by movements in the share price of the Company.
Adjusted general and administrative expenses excluding share-based compensation charges have stayed fairly consistent when 
comparing the periods and amounted to $4.7 million in Q1 2025 compared to $4.3 million in Q1 2024.
Net income/ (loss) and Adjusted net income/ (loss)
Net income as reported by the Company in its Interim Condensed Consolidated Statement of Net Income and Comprehensive Income 
can be impacted by items that are not reflective of the Company’s underlying performance for the period. This might impact the 
comparability of the results of the Company between periods. 
Adjusted net income/ (loss) is a non-GAAP measure. This measure adjusts for the following items and is meant to improve comparability 
between periods:
• Impairment and reversal of impairment is adjusted since this affects the economics of an asset for the lifetime of that asset, not only 
the period in which it is impaired, or the impairment is reversed.
• Share of loss from investments in associates is adjusted since the associated companies are in the exploration phase with the results 
not being reflective of the Company’s underlying performance for the period.
• Other items of income and expenses are adjusted when the impact on net income in the period is not reflective of the Company’s 
underlying performance for the period. 
• Tax effects of the above-mentioned adjustments to net income.
SUMMARY OF QUARTERLY INFORMATION - CONTINUED

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PAGE 23
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
A reconciliation from net income/ (loss) to adjusted net income/ (loss) is shown below:
Three months ended Years ended
Unit
March 31,  
2025
March 31,  
2024
December 31,  
2024
Net income/ (loss) $’m 50.9 3.5 (279.1)
Adjusted for:
Income recognized by Prime under 
Securitization Agreement – net to AOC’s 
shareholding $m
- - (164.8)
Tax effect of income recognized by Prime 
under Securitization Agreement – net to 
AOC’s shareholding $m
- - 16.5
(Reversal of impairment)/ impairment 
investment in Prime $’m (42.9) - 436.7
Share of loss from investments in associates $’m 2.0 14.3 38.7
Adjusted net income $’m 10.0 17.8 48.0
Adjusted net (loss)/ income attributable to common 
shareholders per share
Basic 0.02 0.04 0.11
Diluted 0.02 0.04 0.11
Weighted average number of shares outstanding for the 
purpose of calculating adjusted net income per share
Basic 468,472,433 460,990,598 449,431,803
Diluted 476,836,682 474,745,624 456,462,277
 
Net income amounted to $50.9 million in Q1 2025 (Q1 2024 - $3.5 million). Net income has increased as an impairment reversal of 
$42.9 million was recognized in relation to the investment in Prime during Q1 2025. Prime has been fully consolidated from closing 
date of the amalgamation, March 19, 2025.
Adjusted net income amounted to $10.0 million in Q1 2025 (Q1 2024 - $17.8 million). Adjusted net income in Q1 2025 is lower 
compared to adjusted net income in Q1 2024, mainly driven by higher general and administrative expenses in Q1 2025 relating to the 
transaction with BTG Oil & Gas to acquire the remaining 50% interest in Prime.
SUMMARY OF KEY ITEMS OF FINANCIAL POSITION AS AT MARCH 31, 2025, AND DECEMBER 31, 2024
As at
March 31,  
2025
December 31,  
2024
Assets 
Oil and gas properties 1,588.8 -
Intangible exploration assets 39.0 29.3
Equity investments in associates 143.1 177.6
Trade receivables 156.2 -
Cash and cash equivalents 428.4 61.4
Outstanding bank debt 620.0 -
 
SUMMARY OF QUARTERLY INFORMATION - CONTINUED

===== SIDA 31 =====

PAGE 24
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
Oil and gas properties
Oil and gas properties have increased following closing of the amalgamation to acquire the remaining 50% interest in Prime following 
which Prime is fully consolidated by the Company.
As at March 31, 2025, oil and gas properties amounted to $1,588.8 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 March 31, 2025, the carrying amount of the Company’s intangible exploration assets in Equatorial Guinea was $19.6 million (as at 
December 31, 2024 – $17.9 million) and related to its 80% interest in Blocks EG-18 and EG-31. 
As at March 31, 2025, the carrying amount of the Company’s intangible exploration assets in South Africa was $19.4 million Right (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 March 31, 2025, the Company’s investment in associates was $143.1 million compared to an investment value of $177.6 million as 
at December 31, 2024. The carrying value of the investments decreased by $34.5 million in Q1 2025 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 $141.6 million of 
the total equity investments in associates. 
Trade receivables
Trade receivables have increased following closing of the amalgamation to acquire the remaining 50% interest in Prime following 
which Prime is fully consolidated by the Company. Trade receivables relates to two cargo sales during March with the amounts received 
during April. 
Cash and cash equivalents
Cash and cash equivalents have increased following closing of the amalgamation to acquire the remaining 50% interest in Prime 
following which Prime is fully consolidated by the Company. As at March 31, 2025, the Company had $428.4 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 Prime of $60.0 million prior to the 
closing of the amalgamation, repaid $130.0 million of the RBL facility, returned $8.3 million to shareholders by way of 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 Prime following 
which Prime is fully consolidated by the Company. Subsequent to closing of the amalgamation, the Company pro-actively repaid 
$130.0 million under the RBL facility, reducing outstanding bank debt to $620.0 million as at March 31, 2025. 
SUMMARY OF QUARTERLY INFORMATION - CONTINUED

===== SIDA 32 =====

PAGE 25
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
LIQUIDITY AND CAPITAL RESOURCES 
As at March 31, 2025, the Company had cash balances of $428.4 million and working capital balances (including cash balances) of 
$201.4 million, calculated as current assets less current liabilities as presented in the interim condensed consolidated balance sheet as 
per March 31, 2025. The Company’s primary source of liquidity is operating income in Nigeria and the remaining undrawn amounts on 
the RBL and Corporate Facilities. 
Reserves Based Lending Facility
On amalgamation the Company acquired a Reserves Based Lending Facility (“RBL”). 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 31 of each year, 
limited by aggregate commitments. As of March 31, 2025, the BBA was $720.0 million, which will amortize as the RBL moves towards 
final maturity.
The principal bears interest at Term SOFR + 4.00% until June 2025, then 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 Prime level - Prime is the borrower, and Prime 127 Nigeria Limited and Prime 130 Nigeria Limited 
are the guarantors. The main security package is comprised of security over the shares, production assets, contracts and rights of the 
Nigerian entities - Prime 127 and Prime 130. 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 Prime entities. 
All financial and liquidity covenants covered the RBL are restricted to these three entities. The Prime 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 March 31, 2025.
Corporate Facility
On May 21, 2024, the Company amended its existing Corporate Facility. At any point before Prime refinances its debt, the availability 
under the Corporate Facility will now be $65.0 million until June 30, 2025, $43.0 million from July 1, 2025, until June 30, 2026, and 
$22.0 million from July 1, 2026, to May 21, 2027, i.e. its new final maturity date. After Prime refinances its debt, the availability under 
the Corporate Facility will be $125.0 million until June 30, 2026, and $63.0 million from July 1, 2026, until May 21, 2027. Commitment 
fees of 40% of the margin are payable on the undrawn available portion of the Corporate Facility and commitment fees of 15% of the 
margin are payable on the unavailable portion of the Corporate Facility. The Corporate Facility carries interest of 1 month-SOFR plus a 
margin of 6.5% in the first year from May 21, 2024, 7.0% in the second year and 7.5% in the third year.
The Company provided security in respect of the Corporate Facility mainly in the form of a share pledge over the shares of PetroVida 
(which holds 50% of Prime), and a charge over the bank account into which the Prime distributions are paid. 
The Corporate Facility is subject to financial and liquidity covenants. The Company shall ensure that total net debt to adjusted EBITDAX 
on June 30 and December 31 of each year is no greater than 3.0:1, the FLCR ratio on March 31 and September 30 of each year is not 
less than 1.1:1 and that from March 31 and September 30 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 March 31, 2025. 
Post end of 1Q 2025, the Company has commenced the process to cancel its $65.0 million Corporate Facility, which remains undrawn.
Future Funding Outlook
To finance its future acquisition, exploration, development and operating costs, the Company may require financing from external 
sources, including issuance of new shares, issuance of debt or executing farmout or disposition arrangements. There can be no 
assurance that such financing will be available to the Company or, if available, that it will be offered on terms acceptable to the Company.
The Company believes that its existing cash balances combined with anticipated funds flow from its operations and undrawn facilities 
will provide sufficient liquidity for the Company to meet its financing, operating and capex commitments as they fall due.

===== SIDA 33 =====

PAGE 26
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
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 675,436,334
Outstanding share purchase options 457,616
Outstanding restricted share units 645,507
Outstanding performance share units 6,227,320
Full dilution impact on Common Shares outstanding 682,766,777
 
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 in the three months ended March 31, 2025, and $0.3 million was provided in the 
three months ended March 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 (three months ended March 31, 2024 - $0.1 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 
Limited, Eco’s wholly owned subsidiary, in exchange for all common shares and warrants over common shares held by the Company 
in Eco. On January 13, 2025, the Company announced that it had completed this transaction. The Company’s interest in Block 3B/4B 
increased by 1.0% to 18.0% and the Company ceased to be a shareholder in Eco. Africa Oil 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 a 
subsidiary of the Company and BTG Oil & Gas (see note 13 of the financial statements).  
COMMITMENTS AND CONTINGENCIES
The following commitments and contingencies are representative of the Company’s net obligations at the effective date of the MD&A.
PRIME OIL & GAS COÖPERATIEF U.A:
Under the Prime 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 Prime 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 Prime 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 
$41.1 million in the three months ended March 31, 2025.  
WITHDRAWAL FROM KENYA:
On May 23, 2023, the Kenya entities along with TotalEnergies submitted withdrawal notices to the remaining joint venture party on 
Blocks 10BB, 13T and 10BA in Kenya, to unconditionally and irrevocably, withdraw from the entirety of the JOAs and PSCs for these 
concessions. The Company concurrently submitted notices to Ministry of Energy and Petroleum, requesting the government’s consent 
to transfer all of its rights and future obligations under the PSCs to its remaining joint venture party. Government consent to the transfer 
remained outstanding as at March 31, 2025. 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 March 31, 2025.

===== SIDA 34 =====

PAGE 27
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
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 Prime 127 and Prime 130, cash and cash equivalents in the amount of $234.7 million as per March 31, 
2025, that are held within the projects 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 approximately 50-70% of its next 12-months’ scheduled cargos. As at March 31, 2025, four 
cargos of the Group’s expected lifted entitlement production for the remainder of 2025 are covered by forward contracts. The average 
cargo lifted is for 1 million barrels of oil. The Group’s triggers for the four cargos covered by forward contracts have been triggered in 
April 2025 at an average of $64 per barrel.
CRITICAL ACCOUNTING ESTIMATES 
The Company’s critical accounting estimates are defined as those estimates that have a significant impact on the portrayal of its financial 
position and operations and that require management to make judgements, assumptions and estimates in the application of IFRS 
Accounting Standards. Judgements, assumptions and estimates are based on historical experience and other factors that management 
believes to be reasonable under current conditions. As events occur and additional information is obtained, these judgements, 
assumptions and estimates may be subject to change. 
USE OF ESTIMATES 
The preparation of the consolidated financial statements in conformity with IFRS Accounting Standards requires management to make 
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities 
as at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting 
period. Such estimates include unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, 
actual results may differ from these estimated amounts as future confirming events occur. Significant estimates used in the preparation 
of the consolidated financial statements include, but are not limited to, recovery of exploration costs capitalized in accordance with 
IFRS Accounting Standards, equity method accounting, valuation and impairment of equity investments and contingent consideration 
arising from the acquisition of Prime. 
The Company’ material accounting policies can be found in the Company’s audited consolidated financial statements for the year 
ended December 31, 2024, and in the Company’s unaudited interim condensed consolidated financial statements for the three months 
ended March 31, 2025
OIL AND GAS PROPERTIES
The Company capitalizes costs related to the acquisition of a license interest, directly attributable general and administrative costs, 
expenditures incurred in the process of determining oil and gas exploration targets, and exploration drilling costs.  All exploration 
expenditures that related to properties with common geological structures and with shared infrastructure are accumulated together 
within non-producing oil and gas properties. Costs are held un-depleted until such time as the exploration phases on the license area 
are complete or commercially viable reserves have been discovered and extraction of those reserves is determined to be technically 
feasible.  The determination that a discovery is commercially viable, and extraction is technically feasible requires judgement.  
Where results of exploration drilling indicate the presence of hydrocarbons which are ultimately not considered commercially viable, 
all related costs are recognized in the Consolidated Statement of Net Income and Comprehensive Income. If commercial reserves are 
established and technical feasibility for extraction demonstrated, then the related capitalized non-producing oil and gas properties are 
transferred into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash 
inflows of other assets or groups of assets (CGU) within producing oil and gas properties. The allocation of the Company’s assets into 
CGUs requires judgement.
Non-producing oil and gas properties are assessed for impairment when they are reclassified to producing oil and gas properties, and 
also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.  
The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to dispose.  In assessing 
value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current 
market assessments of the time value of money and the risks specific to the asset.  Value in use is generally computed by reference to 
the present value of the future cash flows expected to be derived from production of proven and probable reserves.  In determining 
fair value less costs to dispose, recent market transactions are taken into account, if available. In the absence of such transactions, an 
appropriate valuation model is used.
The key assumptions the Company uses for estimating future cash flows are the quantity of contingent resources, future commodity 
prices, expected production volumes, future operating and development costs, likelihood of a successful farm out process and 
subsequent timing of FID and discount rate. The estimated useful life of the CGU, the timing of future cash flows and discount rates are 
also important assumptions made by management. 
CRITICAL ACCOUNTING ESTIMATES - CONTINUED

===== SIDA 35 =====

PAGE 28
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
The changing worldwide demand for energy and the global advancement of alternative sources of energy could result in a change 
in the assumptions used to determine the recoverable amount and could affect estimating the future cash flows which could impact 
carrying amount of the Company’s intangible exploration assets. The timing of when global energy markets transition from carbon-
based sources to alternative energy sources is highly uncertain. Environmental considerations are built into our estimates through 
the use of key assumptions in estimating fair value including future commodity prices and discount rates. The energy transition could 
impact the future prices of commodities and discount rates used to appraise oil and gas projects. Pricing assumptions used in the 
determination of recoverable amounts incorporate markets expectations and the evolving worldwide demand for energy.
EQUITY METHOD
Investments in joint ventures and investments in associates are accounted for using the equity method. Investments of this nature are 
recorded at original cost. Investments in joint ventures or associates which arise from a loss in control of a subsidiary are recorded at 
fair value on the date of the loss of control. The investment is adjusted periodically for the Company’s share of the profit or loss of the 
investment after the date of acquisition. The investor’s share of the profit or loss of the investee is also recognized in the Company’s 
Consolidated Statement of Net Income and Comprehensive Income. Distributions received reduce the carrying amount of the 
investment. 
IMPAIRMENT OR REVERSAL OF IMPAIRMENT OF JOINT VENTURES AND ASSOCIATES
The amounts for investments in joint ventures and associates represent the Company’s equity interest in other entities, where there 
is either joint control or significant influence. The Company assesses investments in joint ventures and associates for an objective 
evidence of impairment or reversal of impairment considering changes in circumstances or events which indicate that the carrying 
value may not be recoverable or that the carrying value is below the fair value. The process of determining whether there is an objective 
evidence of impairment or reversal of impairment or calculating the recoverable amount requires judgement. 
CONTINGENT CONSIDERATION
Contingent consideration formed part of the overall consideration for the acquisition of Prime. At the date of acquisition, an estimate 
of the contingent consideration is determined and included as part of the cost of the acquisition. 
Subsequent to acquisition, contingent consideration can be treated using two acceptable methods, the cost-based approach and 
the fair value-based approach. The Company have determined the cost-based approach to give the best estimate of the value of the 
contingent consideration. Any revisions to the contingent consideration estimates, after the date of acquisition, are accounted for as 
changes in estimates in accordance with IAS 8, to be accounted for on a prospective basis. The change in the liability, as a result of the 
revised cash flows, would be adjusted to the cost of the investment and, in accordance with paragraph 37 of IAS 8, recognized as part 
of the investment’s carrying amount rather than in profit or loss.
The estimates involved in assessing the value of the contingent consideration include the expected timing of payments, the expected 
settlement value, the likelihood of settlement and the probability of the assessed outcomes occurring. There is significant judgement 
used in the determination of these estimates.
CLASSIFICATION OF JOINT ARRANGEMENTS
The Group is a party to transactions of non-operated Production Sharing Agreements (“PSAs”). The PSA transactions include the Group’s 
proportionate share of the PSAs assets, liabilities and expenses, with items of a similar nature on a line-by-line basis, from the date that 
participation in the PSA arrangements commenced. 
The Group has applied judgment in determining that it has joint control over the PSAs. This determination recognizes that all major 
decisions outside the original scope of the operations require unanimous approval by at least the Group and one or more of the PSAs 
partners. 
The Group has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions 
of the arrangement, such as approval of the capital expenditure program for each year and appointing, remunerating and terminating 
the key management personnel or service providers of the joint arrangement. The considerations made in determining joint control are 
similar to those necessary to determine control over subsidiaries. 
Classifying the arrangement requires the Group to assess its rights and obligations arising from the arrangement. Specifically, the 
Group considers: 
• The structure of the joint arrangement – whether it is structured through a separate vehicle. 
• When the arrangement is structured through a separate vehicle, the Group also considers the rights and obligations arising from: 
• The legal form of the separate vehicle; 
• The terms of the contractual arrangement; 
• Other facts and circumstances (when relevant). 
As the Group has a proportionate share of the rights to the PSAs’ assets and the obligations for the PSAs’ liabilities, it classifies these 
interests as a Joint Operation under IFRS 11, and presents its proportionate share of the assets, liabilities, revenues and expenses on a 
line-by-line basis in the interim condensed consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES - CONTINUED

===== SIDA 36 =====

PAGE 29
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
This assessment often requires significant judgement, and a different conclusion on joint control and also whether the arrangement is 
a joint operation or a joint venture, may materially impact the accounting. 
If the Group did not have both joint control and a proportionate share of the rights to the PSAs’ assets and obligations for the PSAs’ 
liabilities, it would present only its net investment in the PSAs and its proportionate share of the PSAs’ net income in the consolidated 
financial statements.
ACCOUNTING FOR LEASES AND JOINT OPERATIONS 
Where the Group participates in a joint operation, either as a lease operator or non-operator party, determining whether to recognize 
and whether to measure a lease obligation involves judgement and requires identification of which entity has primary responsibility for 
the lease obligations entered into in relation to the joint operation’s activities. 
Where the joint operation (including all parties to that arrangement) has the right to control the use of the identified asset and all parties 
have a legal obligation to make payments to the third-party supplier, each joint operation participant would recognize its proportionate 
share of the lease related balances. This may arise where all parties to an unincorporated joint operation sign the lease agreement, or 
the joint operation is some sort of entity or arrangement that can sign in its own name. 
However, where the Group is the lead operator and the sole signatory such that it is the one with the legal obligation to pay the third-
party supplier, it would recognize 100% of the lease-related balances on its balance sheet. The Group would then need to assess 
whether the arrangement with the non-operator parties contains a sublease. This assessment would be based on the terms and 
conditions of each arrangement and may be impacted by the legal jurisdiction in which the joint arrangement operates.
Regardless of whether there is a sublease or not, the Group, in case it acts as the lead operator, would continue to recognize the 
lease liability for as long as it remains a party to the arrangement with the third-party supplier and has primary obligation to the lease 
payments.
REVENUE RECOGNITION 
Judgement is required in determining when and how much revenue to recognize from contracts with customers. While the Group has 
determined that all revenue from contracts with customers is earned at a point in time, there is judgement involved in this consideration. 
Contractual arrangements for the sale of different products or with different terms may result in revenue being recognized over time. 
There is also judgement involved in assessing whether the Group is the principal or agent in revenue transactions. In determining that 
the Group is acting as principal, the terms of the agreements were carefully considered and it was concluded that the Group controls 
the product before it is transferred to the customer. In alternate arrangements, the Group could be determined to be acting as agent. 
Under the terms of existing contracts, the Group has determined that shipping or transportation services are not being provided to the 
customer, and that the only performance obligations are for the sale of crude oil and natural gas. Judgement is required in determining 
whether shipping is being provided as a service, and this impacts on the identification of performance obligations, whether all 
performance obligations are recognized at a point in time or over time, and the overall timing of revenue recognition.
Finally, judgement is required to determine whether the contractual arrangements contain only variable consideration, or also 
embedded derivatives, and if variable consideration, whether to exercise the constraint.
TAXES
Judgement is required to determine which arrangements are considered to be a tax on income as opposed to production costs. 
Judgement is also required to determine whether deferred tax assets are recognized in the statement of financial position. Deferred 
tax assets, including those arising from tax losses carried forward, require management to assess the likelihood that the Group will 
generate sufficient taxable earnings in future periods in order to utilize recognized deferred tax assets. 
Assumptions about the generation of future taxable profits depend on management’s estimates of future cash flows. These estimates 
of future taxable income are based on forecast cash flows from operations (which are impacted by production and sales volumes, oil 
and gas prices, reserves, production costs, decommissioning costs, capital expenditure, dividends and other capital management 
transactions) and judgement about the application of existing tax laws in each jurisdiction. 
To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Group to realize the net 
deferred tax assets recorded at the reporting date could be impacted. In addition, future changes in tax laws in the jurisdictions in which 
the Group operates could limit the ability of the Group to obtain tax deductions in future periods.
CRITICAL ACCOUNTING ESTIMATES - CONTINUED

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PAGE 30
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
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 proved and probable reserves could arise due to changes in the factors or assumptions used in estimating reserves, including 
the effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions or 
unforeseen operational issues.
GOING CONCERN
The interim condensed consolidated financial statements for Q1 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.
INTERNAL FINANCIAL REPORTING AND DISCLOSURE 
CONTROLS
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the 
Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, 
summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed 
to ensure that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted 
under securities legislation is accumulated and communicated to the Company’s management, including its Chief Executive Officer 
and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
In accordance with the provisions of NI 52-109, management, including the Chief Executive Officer and the Chief Financial Officer, have 
limited the scope of the design of the Company’s disclosure controls and procedures of Prime. Results for Prime, which was acquired 
on March 19, 2025, reflected in the unaudited interim condensed consolidated financial statements and related notes of the Company 
for the three months ended March 31, 2025, include current assets of $516.8 million, non-current assets of $1,588.9 million, current 
liabilities of $417.0 million, non-current liabilities of $1,026.2 million as of March 31, 2025, and revenues of $76.4 million and profit 
before tax of $10.8 million for the period since the transaction closed. The scope limitation is primarily due to the time required for 
the Company’s management to assess Prime’s controls and procedures in a manner consistent with the Company’s current operations.
Subject to the scope limitation described above, management, including the Chief Executive Officer and Chief Financial Officer, has 
evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures. As of March 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.
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 March 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.
CRITICAL ACCOUNTING ESTIMATES - CONTINUED

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PAGE 31
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
ADVISORY REGARDING OIL AND GAS INFORMATION
The terms boe (barrel of oil equivalent) and MMboe (millions of barrels of oil equivalent) are used throughout this report. Such terms may 
be misleading, particularly if used in isolation. The conversion ratio of six thousand cubic feet per barrel (6 Mcf:1 Bbl) of conventional 
natural gas to barrels of oil equivalent and the conversion ratio of 1 barrel per six thousand cubic feet (1 Bbl:6 Mcf) of barrels of oil to 
conventional natural gas equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and 
does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared 
to conventional natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be 
misleading as an indication of value.
In this report, references are made to historical and potential future oil production in Nigeria and Namibia. In all instances these 
references are to light and medium crude oil category in accordance with NI 51-101 and the COGE Handbook.
Reserves are estimated remaining quantities of petroleum anticipated to be recoverable from known accumulations, as of a given date, 
based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified 
economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of 
certainty associated with the estimates and may be sub-classified based on development and production status. Proved Reserves are 
those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be 
economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods 
and government regulations. Probable Reserves are those additional quantities of petroleum that are less certain to be recovered than 
Proved Reserves, but which, together with Proved Reserves, are as likely as not to be recovered. Possible Reserves are those additional 
reserves that are less certain to be recovered than probable reserves. It is unlikely that actual remaining quantities recovered will exceed 
the sum of the estimated proved plus probable plus possible reserves.
RISK FACTORS
With Board oversight, the Company proactively manages the identification, assessment and mitigation of risks, many of which are 
common to operations in the oil and gas industry as a whole, whilst others are unique to the Company.  The realization of any of the risks 
listed below could have a material adverse effect on the Company’s business, financial condition, reserves and results of operations, 
such list being non-exhaustive.  
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. 
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 Africa Oil does not directly 
control procurement decisions associated with our non-operating 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.
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 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.

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Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
RISK FACTORS - CONTINUED
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. Concerns around climate change have resulted in a 
number of lenders and investors moving away from financing oil and gas activities, and the Company may find access to capital limited, 
more expensive or made contingent upon environmental performance standards.  
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 facilities 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. 
FINANCIAL STATEMENTS PREPARED ON A GOING CONCERN BASIS 
Africa Oil’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. Africa Oil’s operations to date have been financed by 
equity financing, operating cash flows from its assets in Nigeria, dividends received from equity investments, debt financing and the 
completion of working interest farmout agreements. Africa Oil’s future operations may be dependent upon the identification and 
successful completion of additional equity or  debt financing, the achievement of profitable operations or other transactions. There 
can be no assurances that the Company will be successful in completing additional financings, achieving profitability or completing 
future transactions. The consolidated financial statements do not give effect to any adjustments relating to the carrying values and 
classification of assets and liabilities that would be necessary should Africa Oil be unable to continue as a going concern. 
SUBSTANTIAL CAPITAL REQUIREMENTS 
Africa Oil 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.
CURRENT GLOBAL FINANCIAL CONDITIONS 
Global financial conditions have always been subject to volatility. These factors may impact the ability of the Company to obtain equity 
or debt financing in the future, and, if obtained, on terms favorable to the Company. Increased levels of volatility and market turmoil can 
adversely impact the Company’s operations and the value, and the price of the Common Shares could be adversely affected.
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 March 31, 2025. 
INTEREST RATE RISK
The Company has borrowed in the past and has a utilized standby credit facility. Interest payments under potential future borrowings 
could be exposed to volatility in interest rates that could constrain the company’s cashflows.

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Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
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. The risk of the Company’s JV parties defaulting on their obligations per their respective joint operating 
and farmout agreements is mitigated as there are contractual provisions allowing the Company to default JV parties who are non-
performing and reacquire any previous farmed out working interests. The maximum exposure for the Company is equal to the sum of 
its cash, restricted cash, and accounts receivable. A portion of the Company’s cash is held by banks in foreign jurisdictions where there 
could be increased exposure to credit risk.
LIMITATION OF LEGAL REMEDIES 
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.
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, the costs of which 
may be substantial. It is not possible to predict these costs with certainty since they will be a function of requirements at the time of 
decommissioning, abandonment and reclamation and the actual costs may exceed current estimates. Laws, regulations and contractual 
requirements about abandonment and decommissioning may be implemented or amended in the future.
SHAREHOLDER CAPITAL RETURNS 
The Company has implemented a base dividend policy and has in the past engaged in share repurchases as part of its commitment to 
return capital to the shareholders. The amount and frequency of future returns cannot be guaranteed and the Company’s performance 
in this regard is subject to its financial and operational performance that are subject to the risks already outlined. The declaration, 
timing, amount and payment of dividends remain at the discretion of the Company’s Board. Also, the amount and the pace of share 
buybacks, if implemented, are at the discretion of the Board.
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 Africa Oil 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. 
Africa Oil’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.
RESERVES AND RESOURCES VOLUMES 
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. 
RISK FACTORS - CONTINUED

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Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
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. 
INVESTMENTS IN ASSOCIATES 
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.
INTERNATIONAL OPERATIONS 
The Company 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. 
DIFFERENT LEGAL SYSTEM AND LITIGATION 
The Company’s 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. 
The Company’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. 
RISK FACTORS - CONTINUED

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Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
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. 
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 
Africa Oil’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 Africa Oil. 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 Africa Oil. 
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.
RISKS RELATING TO INFRASTRUCTURE
Africa Oil 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 Prime’s 
cashflow and subsequent dividend payments to Africa Oil.
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.
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PAGE 36
Report to Shareholders  |  March 31, 2025 Africa Oil Corp.
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.  
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. 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 environment. 
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 Africa Oil 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 Africa Oil 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.  Africa Oil 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, Africa Oil 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, Africa Oil 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, Africa Oil 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.
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