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Q4
International Petroleum Corporation
Audited Consolidated Financial 
Statements
For the years ended December 31, 2025 and 2024

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2
Contents
Report of Management          3
Report of Independent Auditor                 4
Consolidated Statement of Operations  9
Consolidated Statement of Comprehensive Income/(Loss) 10
Consolidated Balance Sheet 11
Consolidated Statement of Cash Flow 12
Consolidated Statement of Changes in Equity  13
Notes to the Consolidated Financial Statements  14
Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

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3
Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
REPORT OF MANAGEMENT
The accompanying consolidated financial statements of International Petroleum Corporation (“IPC” or the “Corporation” and, 
together with its subsidiaries, the “Group”) and other information contained in the management’s discussion and analysis are the 
responsibility of management and have been approved by the Board of Directors. The consolidated financial statements have been 
prepared by management in accordance with IFRS Accounting Standards as issued by the International Accounting Standards 
Board (“IFRS Accounting Standards”) as outlined in Part 1 of the Handbook of the Chartered Professional Accountants of Canada, 
and include some amounts that are based on management’s estimates and judgment.
The Board of Directors carries out its responsibility for the consolidated financial statements principally through its Audit 
Committee, which is comprised solely of independent directors. The Audit Committee reviews the Group’s annual consolidated 
financial statements and recommends its approval to the Board of Directors. The Corporation’s auditors have full access to the 
Audit Committee, with and without management being present. These consolidated financial statements have been audited by 
PricewaterhouseCoopers LLP , Chartered Professional Accountants, in accordance with Canadian generally accepted auditing 
standards on behalf of the shareholders.
(Signed) William Lundin       (Signed) Christophe Nerguararian 
Director, President and Chief Executive Officer     Chief Financial Officer
Vancouver, Canada
February 10, 2026

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4

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

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5

 
Basis for opinion 
We conducted our audit in accordance with Canadian generally accepted auditing standards. Our 
responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of 
the consolidated financial statements section of our report. 
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our 
opinion. 
Independence 
We are independent of the Corporation in accordance with the ethical requirements that are relevant to our 
audit of the consolidated financial statements in Canada. We have fulfilled our other ethical responsibilities 
in accordance with these requirements. 
Key audit matters 
Key audit matters are those matters that, in our professional judgment, were of most significance in our 
audit of the consolidated financial statements for the year ended December 31, 2025. These matters were 
addressed in the context of our audit of the consolidated financial statements as a whole, and in forming our 
opinion thereon, and we do not provide a separate opinion on these matters. 
Key audit matter How our audit addressed the key audit matter 
  
   
The impact of oil and gas reserves on oil and gas 
properties within net property, plant and equipment 
(PP&E) for the Malaysia segment 
 
Refer to note 1 – Corporate information and material 
accounting policies, note 2 - Critical accounting estimates and 
judgements, and note 9 - Property, plant and equipment to the 
consolidated financial statements. 
 
The Malaysia segment had $86.1 million of oil and gas 
properties within PP&E, as at December 31, 2025, and 
Our approach to addressing the matter included the following 
procedures, among others: 
• Tested how management determined the total proved and 
probable oil and gas reserves for the Malaysia segment, 
which included the following:

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6

 
depletion charges were $24.2 million for the year then ended. 
Oil and gas properties are depleted based on the year's 
production in relation to the estimated total proved and 
probable oil and gas reserves in accordance with the unit of 
production method. Significant assumptions developed by 
management used to determine the proved and probable oil 
and gas reserves include expected production volumes, future 
oil and gas prices, future development costs and future 
production costs. Independent qualified reserves auditors 
(management’s experts) review these estimates. 
 
We considered this a key audit matter due to i) the judgments 
by management, including the use of management’s experts, 
when estimating the proved and probable oil and gas reserves 
and ii) a high degree of auditor judgment, subjectivity and effort 
in performing procedures relating to the significant 
assumptions. 
- The work of management’s experts was used in 
performing the procedures to evaluate the 
reasonableness of the proved and probable oil 
and gas reserves used to determine the depletion 
charges. As a basis for using this work, the 
competence, capabilities and objectivity of 
management’s experts were evaluated, the work 
performed was understood and the 
appropriateness of the work as audit evidence 
was evaluated. The procedures performed also 
included evaluation of the methods and 
assumptions used by management’s experts, 
tests of data used by management’s experts and 
an evaluation of their findings. 
- Evaluated the reasonableness of significant 
assumptions used, including expected production 
volumes, future development costs and future 
production costs by considering current and past 
performance of the Corporation and whether 
these assumptions were consistent with evidence 
obtained in other areas of the audit, as 
applicable. 
- Evaluated the reasonableness of future oil and 
gas prices by comparing them with third party 
industry forecasts. 
• Recalculated the depletion charge for the Malaysia 
segment. 
Other information 
Management is responsible for the other information. The other information comprises the Management’s 
Discussion and Analysis. 
Our opinion on the consolidated financial statements does not cover the other information and we do not 
express any form of assurance conclusion thereon.

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7

 
In connection with our audit of the consolidated financial statements, our responsibility is to read the other 
information identified above and, in doing so, consider whether the other information is materially 
inconsistent with the consolidated financial statements or our knowledge obtained in the audit, or otherwise 
appears to be materially misstated. 
If, based on the work we have performed, we conclude that there is a material misstatement of this other 
information, we are required to report that fact. We have nothing to report in this regard. 
Responsibilities of management and those charged with governance for the 
consolidated financial statements 
Management is responsible for the preparation and fair presentation of the consolidated financial 
statements in accordance with IFRS Accounting Standards, and for such internal control as management 
determines is necessary to enable the preparation of consolidated financial statements that are free from 
material misstatement, whether due to fraud or error. 
In preparing the consolidated financial statements, management is responsible for assessing the 
Corporation’s ability to continue as a going concern, disclosing, as applicable, matters related to going 
concern and using the going concern basis of accounting unless management either intends to liquidate the 
Corporation or to cease operations, or has no realistic alternative but to do so. 
Those charged with governance are responsible for overseeing the Corporation’s financial reporting process. 
Auditor’s responsibilities for the audit of the consolidated financial statements 
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a 
whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report 
that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an 
audit conducted in accordance with Canadian generally accepted auditing standards will always detect a 
material misstatement when it exists. Misstatements can arise from fraud or error and are considered

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8

 
material if, individually or in the aggregate, they could reasonably be expected to influence the economic 
decisions of users taken on the basis of these consolidated financial statements. 
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise 
professional judgment and maintain professional skepticism throughout the audit. We also: 
• Identify and assess the risks of material misstatement of the consolidated financial statements, whether 
due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit 
evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a 
material misstatement resulting from fraud is higher than for one resulting from error, as fraud may 
involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. 
• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that 
are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness 
of the Corporation’s internal control. 
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates 
and related disclosures made by management. 
• Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based 
on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that 
may cast significant doubt on the Corporation’s ability to continue as a going concern. If we conclude that 
a material uncertainty exists, we are required to draw attention in our auditor’s report to the related 
disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our 
opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. 
However, future events or conditions may cause the Corporation to cease to continue as a going concern. 
• Evaluate the overall presentation, structure and content of the consolidated financial statements, 
including the disclosures, and whether the consolidated financial statements represent the underlying 
transactions and events in a manner that achieves fair presentation. 
• Plan and perform the group audit to obtain sufficient appropriate audit evidence regarding the financial 
information of the entities or business units within the Corporation as a basis for forming an opinion on

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9

 
the consolidated financial statements. We are responsible for the direction, supervision and review of the 
audit work performed for purposes of the group audit. We remain solely responsible for our audit opinion. 
We communicate with those charged with governance regarding, among other matters, the planned scope 
and timing of the audit and significant audit findings, including any significant deficiencies in internal 
control that we identify during our audit. 
We also provide those charged with governance with a statement that we have complied with relevant ethical 
requirements regarding independence, and to communicate with them all relationships and other matters 
that may reasonably be thought to bear on our independence, and where applicable, related safeguards. 
From the matters communicated with those charged with governance, we determine those matters that were 
of most significance in the audit of the consolidated financial statements of the current period and are 
therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation 
precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a 
matter should not be communicated in our report because the adverse consequences of doing so would 
reasonably be expected to outweigh the public interest benefits of such communication. 
The engagement partner on the audit resulting in this independent auditor’s report is Kory Wickenhauser. 
 
Chartered Professional Accountants 
Calgary, Alberta 
February 10, 2026

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10
Consolidated Statement of Operations
For the years ended December 31, 2025 and 2024, AUDITED
USD Thousands Note 2025 2024
Revenue 3 685,888 797,783
Cost of sales
Production costs 4 (427,623) (448,218)
Depletion and decommissioning costs 3,9 (122,749) (128,392)
Depreciation of other tangible fixed assets 3,9 (5,597) (8,933)
Exploration and business development costs 3 (1,799) (2,069)
Gross profit 3 128,120 210,171
Other income / (expense) 751 1,137
General and administrative expenses (16,784) (16,055)
Profit before financial items 112,087 195,253 
Finance income 5 18,088 17,721
Finance costs 6 (83,853) (77,430)
Net financial items (65,765) (59,709)
Profit before tax 46,322 135,544
Income tax expense 7 (17,380) (33,325)
Net result 28,942 102,219
Net result attributable to:
Shareholders of the Parent Company 28,938 102,202
Non-controlling interest 4 17
28,942 102,219
Earnings per share – USD1 16 0.25 0.82
Earnings per share fully diluted – USD1 16 0.25 0.81
1  Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the consolidated financial statements

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11
Consolidated Statement of Comprehensive Income/(Loss)
For the years ended December 31, 2025 and 2024, AUDITED
USD Thousands Note 2025 2024
Net result 28,942 102,219
Other comprehensive income/(loss)
Items that may be reclassified to profit or loss:
Reclassification of hedging (gains)/losses to profit or 
loss 3, 6, 22 (14,650) (22,370)
Gain/(loss) on cash flow hedges 34,700 (35,498)
Income tax relating to these items (4,668) 13,753
Currency translation adjustments 50,651 (73,931)
Items that will not be reclassified to profit or loss:
Re-measurements on defined pension plan 20 654 (3,491)
Total comprehensive income/(loss) 95,629 (19,318)
Total comprehensive income/(loss) attributable to:
Shareholders of the Parent Company 95,620 (19,329)
Non-controlling interest 9 11
95,629 (19,318)
See accompanying notes to the consolidated financial statements

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12
Consolidated Balance Sheet
As at December 31, 2025 and 2024, AUDITED
USD Thousands Note December 31, 2025 December 31, 2024
ASSETS
Non-current assets
Exploration and evaluation assets 8 11,623 480
Property, Plant and Equipment 9 1,783,498 1,500,912
Right-of-use assets 10 3,070 3,103
Deferred tax assets 7 1,635 1,673
Derivative instruments 22, 23 1,285 –
Other non-current assets 11 46,216 48,665
Total non-current assets 1,847,327 1,554,833
Current assets
Inventories 12 19,990 20,073
Trade and other receivables 13 97,220 127,450
Derivative instruments 22, 23 1,644 3,219
Current tax receivables 4,411 1,514
Cash and cash equivalents 14 7,037 246,593
Total current assets 130,302 398,849
TOTAL ASSETS 1,977,629 1,953,682
LIABILITIES
Non-current liabilities
Financial liabilities 18, 22 38,709 1,719
Bonds 18, 22 442,324 439,862
Lease liabilities 10 2,956 2,728
Provisions 19 284,202 268,509
Deferred tax liabilities 7 122,013 92,754
Derivative instruments 22, 23 – 562
Total non-current liabilities 890,204 806,134
Current liabilities
Trade and other payables 21 149,708 176,371
Financial liabilities 18, 22 1,943 3,402
Derivative instruments 22, 23 422 19,869
Current tax liabilities 216 1,146
Lease liabilities 10 930 573
Provisions 19 7,029 6,717
Total current liabilities 160,248 208,078
EQUITY
Shareholders’ equity 927,029 939,315
Non-controlling interest 148 155
Net shareholders’ equity 927,177 939,470
TOTAL EQUITY AND LIABILITIES 1,977,629 1,953,682
Approved by the Board of Directors
(Signed) C. Ashley Heppenstall    (Signed) William Lundin
Director       Director
See accompanying notes to the consolidated financial statements

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13
Consolidated Statement of Cash Flow
For the years ended December 31, 2025 and 2024, AUDITED
USD Thousands Note 2025 2024
Cash flow from operating activities
Net result 28,942 102,219
Depletion, depreciation and amortization 3, 9,10 129,754 138,566
Write-off of exploration costs 8 714 1,419
Income tax 7 17,380 33,325
Amortization of capitalized financing fees 6 4,370 2,057
Foreign currency exchange loss/(gain) 6 (14,654) 23,427
Interest income 5 (3,160) (17,721)
Interest expense 6 41,983 35,905
Unwinding of asset retirement obligation discount 6 16,498 14,568
Change in pension liability 20 816 682
Share-based costs 17 9,562 8,539
Changes in working capital  10,449 (47,092)
Decommissioning costs paid 19 (5,967) (7,711)
Other payments 19 (2,448) (1,997)
Net income taxes paid (3,500) (6,362)
Interest received 3,620 18,619
Interest paid (41,317) (32,821)
Other 954 465
Net cash flow from operating activities 193,996 266,087
Cash flow used in investing activities
Investment in oil and gas properties 9 (333,206) (432,794)
Investment in exploration and evaluation assets 8 (12,362) (1,919)
Disposal of assets 9 – 221 
Investment in other tangible fixed assets (640) (363)
Net cash (outflow) from investing activities (346,208) (434,855)
Cash flow from financing activities
Proceeds from borrowings 18 38,709 –
Repayment of borrowings 18 (3,178) (3,910)
Bonds issuance proceeds 18 450,000 –
Repayment of Bonds 18 (450,000) –
Paid financing fees (8,765) –
Repurchase of own shares (“NCIB”) 15 (100,264) (102,188)
Lease payment (976) (964)
Dividend paid (16) (41)
Net cash (outflow) from financing activities (74,490) (107,103)
Change in cash and cash equivalents (226,702) (275,871)
Cash and cash equivalents at the beginning of the 
year 246,593 517,074 
Currency exchange difference in cash and cash 
equivalents (12,854) 5,390
Cash and cash equivalents at the end of the year 7,037 246,593 
   
See accompanying notes to the consolidated financial statements

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14
Consolidated Statement of Changes in Equity
For the years ended December 31, 2025 and 2024, AUDITED
USD Thousands
Share 
capital and 
premium
Retained 
earnings CTA IFRS 2 
reserve
MTM 
reserve
Pension 
reserve Total
Non-
controlling 
interest
Total
equity
Balance at January 1, 2025 141,173 875,952 (81,192) 18,092 (13,138) (1,572) 939,315 155 939,470
Net result –  28,938     – – – –  28,938    4 28,942
Re-measurements on defined 
pension plan – – – – – 654 654 – 654
Cash flow hedges – – – – 15,382 – 15,382 – 15,382
Currency translation difference – – 50,598 867 (331) (488) 50,646 5 50,651  
Total comprehensive income –     28,938     50,598     867     15,051     166     95,620     9     95,629    
Repurchase of own shares1 (100,264) – – – – – (100,264) – (100,264)
Dividend Distribution – – – – – – – (16) (16)
Share based costs – – – 9,562 – – 9,562 – 9,562 
Share based payments2 – (8,198) – (9,006) – – (17,204) – (17,204)
Balance at December 31, 2025 40,909 896,692 (30,594) 19,515 1,913 (1,406) 927,029 148 927,177 
1  See Note 15
2 The third instalment of IPC RSP 2022 awards, the second instalment of IPC RSP 2023 awards, the first instalment of IPC RSP 2024 awards and 
the IPC PSP 2022 awards vested on February 1, 2025, at a price of CAD 18.89 per award. The difference between the value at vesting date and 
at grant (respectively CAD 9.09 per award, CAD 14.24 per award, CAD 14.82 per award and CAD 8.40 per award) was offset against retained 
earnings. 
USD Thousands
Share 
capital and 
premium
Retained 
earnings CTA IFRS 2 
reserve
MTM 
reserve
Pension 
reserve Total
Non-
controlling 
interest
Total
equity
Balance at January 1, 2024 243,361 795,490 (10,745) 18,838 31,344 1,786 1,080,074 185 1,080,259
Net result – 102,202 – – – – 102,202 17 102,219
Re-measurements on defined 
pension plan – – – – – (3,491) (3,491) – (3,491)
Cash flow hedges – – – – (44,115) – (44,115) – (44,115)
Currency translation difference – – (70,447) (3,244) (367) 133 (73,925) (6) (73,931)
Total comprehensive income – 102,202 (70,447) (3,244) (44,482) (3,358) (19,329) 11 (19,318)
Repurchase of own shares1 (102,188) – – – – – (102,188) – (102,188)
Dividend distribution – – – – – – – (41) (41)
Share based costs – – – 8,629 – – 8,629 – 8,629
Share based payments2                     – (21,740) – (6,131) – – (27,871) – (27,871)
Balance at December 31, 2024 141,173 875,952 (81,192) 18,092 (13,138) (1,572) 939,315 155 939,470
1 See Note 15
2 The third instalment of IPC RSP 2021 awards, the second instalment of IPC RSP 2022 awards, the first instalment of IPC RSP 2023 awards and 
the IPC PSP 2021 awards vested on February 1, 2024, at a price of CAD 14.90 per award. The difference between the value at vesting date and 
at grant (respectively CAD 4.07 per award, CAD 9.09 per award, CAD 14.27 per award and CAD 3.61 per award) was offset against retained 
earnings. 
See accompanying notes to the consolidated financial statements

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15
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
1. CORPORATE INFORMATION AND MATERIAL ACCOUNTING POLICIES
A. The Group
International Petroleum Corporation (“IPC” or the “Corporation” and, together with its subsidiaries, the “Group”) is in the business 
of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development 
projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in 
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada under the Business Corporations Act. The 
address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is 
Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
B. Basis of preparation
The consolidated financial statements have been prepared in accordance with IFRS Accounting Standards as issued by
the International Accounting Standards Board (“IFRS Accounting Standards”).
These consolidated financial statements are presented in United States Dollars (USD), which is the Group’s presentation and
functional currency. The consolidated financial statements have been prepared on a historical cost basis, except for items that are
required to be accounted for at fair value as detailed in the Group’s accounting policies. Intercompany transactions and balances
have been eliminated.
These consolidated financial statements have been approved by the Board of Directors of IPC and authorized for issuance on
February 10, 2026.
C. Change in presentation
Certain comparative figures have been reclassified to conform with the financial statements presentation in the current year.
D. Going concern
The Group’s consolidated financial statements for the year ended December 31, 2025, have been prepared on a going concern
basis, which assumes that the Group will be able to realize its assets and discharge its liabilities in the normal course of business
as they become due in the foreseeable future.
E. Changes in accounting policies and disclosures
During the year ended December 31, 2025, the Group applied the amended accounting standards, interpretations and annual
improvement points that are effective as of January 1, 2025. The application of the amendments did not have a material impact on
the consolidated financial statements.
There are no plans for the early adoption of published standards, interpretations, or amendments prior to their mandatory effective
date. The Group does not expect that other changes in IFRS Accounting Standards will have a material impact on the consolidated
financial statements.
F. Future accounting changes 
Recent amendments to IFRS 9 and related IFRS 7 disclosure requirements address the settlement of financial liabilities via 
electronic payment systems and refine the assessment of contractual cash flow characteristics for financial assets.  The 
amendments are effective for annual reporting periods beginning on or after January 1, 2026. These changes are not expected to 
have a material impact on the financial statements.
IFRS 18 replaces IAS 1 and introduces expanded requirements for how financial information is presented and disclosed. The 
standard adds new subtotals, categories for income and expenses, and mandates disclosure of management performance 
measures. It also enhances rules around aggregation and disaggregation. Adoption is retrospective, and the Corporation is 
currently assessing system changes, preparing draft disclosures, and planning comparative restatements ahead of the 2027 
effective date.

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16
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
G. Basis of Consolidation
Subsidiaries
Subsidiaries are all entities over which the Group has control and are consolidated. The Corporation controls an entity when it is
exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through
its power over the entity.
The non-controlling interest in a subsidiary represents the portion of the subsidiary not owned by Group companies. The equity of
the subsidiary relating to the non-controlling shareholders is shown as a separate item within changes in net equity.
Inter-company transactions, balances, income and expenses on transactions between companies are eliminated. Profits and losses
resulting from intercompany transactions that are recognized in assets are also eliminated.
H. Joint Arrangements
Oil and gas operations of the Group are conducted as co-licensees in unincorporated joint ventures with other companies and are
classified as joint operations. The consolidated financial statements reflect the relevant proportions of production, capital costs,
operating costs and current assets and liabilities of the joint operation applicable to the Corporation’s interests.
I. Foreign Currency Translation
Transactions and balances
Monetary assets and liabilities denominated in foreign currencies are translated at the rates of exchange prevailing at the balance 
sheet date and foreign exchange currency differences are recognized in the consolidated statement of operations. Transactions 
in foreign currencies are translated at exchange rates prevailing at the transaction date. Foreign exchange gains and losses are 
presented within finance income and costs in the consolidated statement of operations.
Functional and presentation currency
Items included in the financial statements of each of the operational entities are measured using the currency of the primary 
economic environment in which the entity operates (the “functional currency”). The functional currency of the Corporation’s 
operational entities are the USD, CAD, MYR and EUR. The consolidated financial statements are presented in USD which is the 
Corporation’s presentation currency. The balance sheets and income statements of foreign companies are translated using the 
current rate method. All assets and liabilities are translated at the balance sheet date rates of exchange, whereas the income 
statements are translated at average rates of exchange for the year, except for transactions where it is more relevant to use the 
rate of the day of the transaction. The translation differences which arise are recorded directly in net assets.
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
December 31, 2025 December 31, 2024
Average Year end Average Year end
1 EUR equals USD 1.1293 1.1750 1.0821 1.0389
1 USD equals CAD 1.3975 1.3692 1.3698 1.4388
1 USD equals MYR 4.2791 4.0580 4.5759 4.4715
J. Classification of assets and liabilities
Non-current assets, long-term liabilities and provisions consist of amounts that are expected to be recovered or paid more than 
twelve months after the balance sheet date. Current assets and current liabilities consist solely of amounts that are expected to be 
recovered or paid within twelve months after the balance sheet date.
K. Exploration and evaluation assets
Costs directly associated with an exploration well are capitalized until the determination of reserves is evaluated. If it is determined 
that a commercial discovery has not been achieved or if there is a decision to not continue with a field specific exploration 
program, the costs will be expensed at the time the decision is made. During the exploration and development phases, no 
depletion is charged. The field will be transferred from the non-producing assets to the producing assets within oil and gas 
properties once production commences and accounted for as a producing asset. 
L. Property, Plant and Equipment
Oil and gas properties
Oil and gas properties are recorded at historical cost less depletion. All costs for acquiring concessions, licences or interests in 
production sharing contracts and for the survey, drilling and development of such interests are capitalized on a field area cost 
center basis. Routine maintenance costs for producing assets are expensed to the statement of operations when they occur.

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17
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
Oil and gas properties are depleted based on the year’s production in relation to estimated total proved and probable reserves of 
oil and gas in accordance with the unit of production method. Depletion of a field area is charged to the statement of operations 
through cost of sales once production commences.
Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated 
with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current 
economic conditions, operating methods and governmental regulations. Proved reserves can be categorized as developed or 
undeveloped. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence 
that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the 
quantities actually recovered will equal or exceed the estimates.
Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than 
not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50 percent probability that 
the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.
Proceeds from the sale or farm-out of oil and gas concessions in the exploration stage are offset against the related capitalized 
costs of each cost center with any excess of net proceeds over the costs capitalized included in the statement of operations. In 
the event of a sale in the exploration stage, any deficit is included in the statement of operations.
When there are facts and circumstances that suggest that the net book value of capitalized costs within each field area cost 
center is higher than anticipated future net cash flow from oil and gas reserves attributable to the Corporation’s interest in the 
related field areas, the Corporation performs an assessment as to whether an asset may be impaired. Management determines 
the recoverable amounts of property, plant and equipment based on the higher of fair value less costs of disposal and value in use 
using estimated future discounted net cash flows of proved and probable oil and gas reserves. The Corporation’s estimates of 
proved and probable oil and gas reserves used in the calculations for impairment tests and accounting for depletion are reviewed 
annually by Management’s experts, specifically independent qualified reserves auditor (“IQRE”).
The recoverable amount of the asset or cash-generating unit (“CGU”) is estimated as the the higher of fair value less costs of 
disposal (“FVLCOD”) and value in use (“VIU”). In determining FVLCOD, recent market transactions are considered, if available. In 
the absence of such transactions, FVLCOD is estimated based on the discounted after-tax cash flows of reserves using forward 
prices, costs to develop and operating costs, consistent with IPC’s IQREs. Value in use is estimated by discounting future cash 
flows expected to arise from the continuing use of a CGU or asset, to their present value, using a discount rate that reflects 
current market assessments of the time value of money and the risks specific to the asset. When the recoverable amount is less 
than the carrying value an impairment loss is recognized with the expensed charge to the statement of operations. If indications 
exist that previously recognized impairment losses no longer exist or are decreased, the recoverable amount is reversed. When 
a previously recognized impairment loss is reversed the carrying amount of the asset is increased to the estimated recoverable 
amount but the increased carrying amount may not exceed the carrying amount after depreciation that would have been 
determined had no impairment loss been recognized for the asset in prior years. If the asset does not generate cash inflows that 
are largely independent of those from other assets or groups of assets, the asset is tested as part of a CGU, which is the smallest 
identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or 
groups of assets. 
Other tangible fixed assets
Other tangible fixed assets are stated at cost less accumulated depreciation. The cost includes the original purchase price of the 
asset and the costs attributable to bringing the asset to its working condition for its intended use. Depreciation is based on cost 
and is calculated on a straight line basis over the estimated economic life of 3 to 5 years for office equipment and other assets. 
The Floating Production Storage and Offloading (“FPSO”) located on the Bertam field, Malaysia, has been depreciated to its 
residual value.
Additional costs to existing assets are included in the assets’ net book value or recognized as a separate asset, as appropriate, only 
when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be 
measured reliably. The net book value of any replaced parts is written off. Other additional expenses are deemed to be repair and 
maintenance costs and are charged to the statement of operations when they are incurred.
The net book value is written down immediately to its recoverable amount when the net book value is higher. The recoverable 
amount is the higher of an asset’s fair value less cost of disposal and value in use. The assets’ residual values and useful lives are 
reviewed, and adjusted if appropriate, at the end of each reporting period.
M. Leases
The Group leases various offices, warehouses, equipment and cars. Rental contracts are typically made for fixed periods of 3 to 
5 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different 
terms and conditions. 
Right-of-use assets and corresponding liabilities are recognized when the leased asset is available for use by the Group. Each 
lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the period so 
as to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is 
depreciated over the shorter of the asset’s useful life and the lease term on a straight-line basis.

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

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Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present 
value of the fixed and variable lease payments and the exercise price of the purchase option. The lease payments are discounted 
using the incremental borrowing rate and are classified as finance leases. The right-of-use assets are measured at cost comprising 
the amount of the initial measurement of the lease liability, any lease payments made and any initial direct costs.
Payments associated with short-term leases and leases of low-value assets are recognized on a straight-line basis as an expense 
in profit or loss.
N. Financial Instruments
Financial assets and financial liabilities are recognized on the consolidated balance sheet on the trade date, the date on which 
the Group becomes a party to the contractual provisions of the financial instrument. All financial instruments are required to 
be classified and measured at fair value on initial recognition. Measurement in subsequent periods is dependent upon the 
classification of the financial instrument. The Group classifies its financial instruments in the following categories: 
Financial Assets at Amortized Cost
Assets that are held for collection of contractual cash flows where those cash flows represent solely payments of principal and 
interest are measured at amortized cost. The Group’s loans and receivables consist of fixed or determined cash flows related 
solely to principal and interest amounts or contractual sales of oil. The Group’s intent is to hold these receivables until cash flows 
are collected. Loans and receivables are recognized initially at fair value, net of any transaction costs incurred and subsequently 
measured at amortized cost. 
Financial Assets at Fair Value through Profit or Loss (“FVTPL”)
Financial assets measured at FVTPL are assets which do not qualify as financial assets at amortized cost or at fair value through 
other comprehensive income. 
Financial Liabilities at Amortized Cost
Financial liabilities are measured at amortized cost, unless they are required to be measured at FVTPL, or the Group has opted 
to measure them at FVTPL. Borrowings and accounts payable are recognized initially at fair value, net of any transaction costs 
incurred, and subsequently at amortized cost using the effective interest method.
Financial Liabilities at FVTPL
Financial liabilities measured at FVTPL are liabilities which include embedded derivatives and cannot be classified as amortized 
cost. 
Impairment of Financial Assets
The measurement of impairment of financial assets is based on the expected credit losses model. For the trade and other 
receivables, the Group applies the simplified approach which requires the use of the lifetime expected loss provision for all trade 
receivables. In estimating the lifetime expected loss provision, the Group considered historical industry default rates as well as 
credit ratings of major customers. Additional disclosure related to the Group’s financial assets is included in Note 22.
O. Derivative Financial Instruments and Hedging Activities
Derivatives are initially recognized at fair value on the date a derivative contract is entered into and are subsequently remeasured 
to their fair value. The method of recognizing the resulting gain or loss depends on whether the derivative is designated as a 
hedging instrument, and if so, the nature of the item being hedged. The Group designates certain derivatives as either hedges of a 
particular risk associated with a recognized asset or liability or a highly probable forecasted transaction, hedges of the fair value of 
recognized assets and liabilities or a firm commitment, or hedges of a net investment in a foreign operation. 
The Group documents at the inception of the transaction the relationship between hedging instruments and the hedged items, as 
well as its risk management objectives and strategy for undertaking various hedging transactions. The Group also documents its 
assessment, both at hedge inception and on an ongoing basis, of whether the derivatives that are used in hedging transactions 
are highly effective in offsetting changes in fair values or cash flows of the hedged items. The fair values of various derivative 
financial instruments used for hedging purposes are disclosed in Note 22. Movements on the hedging reserve is reflected in other 
comprehensive income. The full fair value of a hedging derivative is classified as a non-current asset or liability when the remaining 
maturity of the hedged item is more than twelve months and as a current asset or liability when the remaining maturity of the 
hedged item is less than twelve months. 
Cash flow hedge 
The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized in 
other comprehensive income. The gain or loss relating to the ineffective portion, if any, is recognized immediately within statement 
of operations. Amounts accumulated in equity are reclassified to profit or loss in the periods when the hedged item affects 
profit or loss. When a hedging instrument expires or is sold, or when a hedge no longer meets the criteria for hedge accounting, 
any cumulative gain or loss existing in equity at that time remains in equity and is recognized when the forecast transaction is 
ultimately recognized in the statement of operations. When a forecasted transaction is no longer expected to occur, the cumulative 
gain or loss that was reported in equity is immediately recognized in the statement of operations.

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P . Inventories
Inventories of consumable well supplies are stated at the lower of cost and net realizable value, cost being determined on a 
weighted average cost basis. Net realizable value is the estimated selling price in the ordinary course of business, less applicable 
variable selling expenses. Inventories of hydrocarbons are stated at the lower of cost and net realizable value. Under or overlifted 
positions of hydrocarbons are valued at market prices prevailing at the balance sheet date. An underlift of production from a field 
is included in the current receivables and valued at the reporting date spot price or prevailing contract price and an overlift of 
production from a field is included in the current liabilities and valued at the reporting date spot price or prevailing contract price. 
A change in the over or underlift position is reflected in the statement of operations as revenue.
Q. Cash and cash equivalents
Cash and cash equivalents include cash at bank and cash in hand.
R. Provisions 
A provision is reported when the Group has a legal or constructive obligation as a consequence of a past event and when it is 
more likely than not that an outflow of resources is required to settle the obligation and a reliable estimate can be made of the 
amount.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a discount 
rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in 
the provision due to passage of time is recognized as financial expense.
On fields where there is an obligation to contribute to asset retirement obligation costs, a provision is recorded to recognize the 
future commitment. An asset is created, as part of the oil and gas property, to represent the discounted value of the anticipated 
asset retirement obligation liability and depleted over the life of the field on a unit of production basis. The corresponding 
accounting entry to the creation of the asset recognizes the discounted value of the future liability. The discount applied to 
the anticipated asset retirement obligation liability is subsequently released over the life of the field and is charged to financial 
expenses. Changes in asset retirement obligation costs and reserves are treated prospectively and consistent with the treatment 
applied upon initial recognition.
S. Revenue and Other Operating Revenue
Revenue associated with the sale of crude oil and natural gas is measured based on the consideration specified in a contract with 
a customer and excludes amounts collected on behalf of third parties. The Group recognizes revenue when it transfers control of 
the product or service to a customer, which is generally when title passes from the Group to its customer. The Group satisfies its 
performance obligations in contracts with customers upon the delivery of crude oil and natural gas, which is generally at a point in 
time.
Royalties payments to governments and other mineral interest owners are recognized as a cost in the revenue section.
Production and sales taxes directly attributable to fields, including export duties, are expensed in the statement of operations 
and classified as direct production taxes included within production costs. Production taxes payable in cash are accrued in the 
accounting period in which the liability arises.
T. Employee Benefits
Short-term employee benefits
Short-term employee benefits such as salaries, social premiums and holiday pay, are expensed when incurred.
Pension obligations
The pension obligations consist of defined contribution plans for all companies within the Group except for one Swiss subsidiary, 
International Petroleum SA. A defined contribution plan is a pension plan under which the Group pays fixed contributions. The 
Group has no further payment obligations once the contributions have been paid. The contributions are recognized as an expense 
when they are due.
International Petroleum SA has a defined benefit pension plan that is managed through a private pension plan. Independent 
actuaries determine the cost of the defined benefit plan on an annual basis, and the subsidiary pays the annual insurance premium. 
The pension plan provides benefits coverage to the employees of International Petroleum SA in the event of retirement, death or 
disability. International Petroleum SA and its employees jointly finance retirement and risk benefits. Employees of International 
Petroleum SA pay 40% of the savings contributions, of the risk contributions and of the cost contributions and International 
Petroleum SA contributes the difference between the total of all required pension plan contributions and the total of all employees’ 
contributions.
Share-based payments
The Group operates an equity-settled, share-based compensation plan under which the entity receives services from employees, 
directors and officers as consideration for equity instruments of the Corporation. Equity-settled share-based payments are 
recognized in the statement of operations as expenses during the vesting period and as equity in the balance sheet. The option 
is measured at fair value at the date of the grant using an appropriate options pricing model and is charged to the statement of 
operations over the vesting period without revaluation of the value of the option.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

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20
U. Taxation
The components of tax are current and deferred. Tax is recognized in the statement of operations, except to the extent that it 
relates to items recognized in other comprehensive income or directly in equity, in which case it is accounted for consistently with 
the related item.
Current tax is tax that is to be paid or received for the year in question and also includes adjustments of current tax attributable to 
previous periods.
Deferred income tax is a non-cash charge provided, using the liability method, on temporary differences arising between the 
tax bases of assets and liabilities and their carrying values. Temporary differences can occur for example where investment 
expenditure is capitalized for accounting purposes but the tax deduction is accelerated or where asset retirement obligation 
costs are provided for in the financial statements but not deductible for tax purposes until they are actually incurred. However, 
the deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a 
business combination that at the time of the transaction affects neither accounting nor taxable profit nor loss.
Deferred income tax is provided on temporary differences arising on investments in subsidiaries and associates, except where the 
timing of the reversal of the temporary difference is controlled by the Corporation and it is probable that the temporary difference 
will not reverse in the foreseeable future. Deferred income tax is determined using tax rates (and laws) that have been enacted or 
substantively enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realized 
or the deferred income tax liability is settled. Deferred income tax assets are recognized to the extent that it is probable that future 
taxable profit will be available against which the temporary differences can be utilized.
Deferred tax assets are offset against deferred tax liabilities in the balance sheet where they relate to the same jurisdiction and 
there is a legally enforceable right to offset.
V. Segment Reporting
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker, 
which, due to the unique nature of each country’s operations, commercial terms or fiscal environment, is at a country level. 
W. Business Combinations
Acquisitions of businesses are accounted for using the purchase method of accounting whereby all identifiable assets and 
liabilities are recorded at their fair values as at the date of acquisition. Any excess purchase price over the aggregate fair value of 
net assets is recorded as goodwill. Goodwill is identified and allocated to CGU, or groups of CGUs, that are expected to benefit 
from the synergies of the acquisition. Goodwill is not amortized. Any excess of the aggregate fair value of net assets over the 
purchase price is recognized in the consolidated statement of operations.
A CGU to which goodwill has been allocated is tested for impairment at least annually or when events or circumstances indicate 
that an assessment for impairment is required. For goodwill arising on an acquisition in a financial year, the CGU to which the 
goodwill has been allocated is tested for impairment before the end of that financial year.
When the recoverable amount of the CGU is less than the carrying amount of that CGU, the impairment loss is allocated to 
reduce the carrying amount of any goodwill allocated to that CGU first, and then to the other assets of that CGU pro rata on the 
basis of the carrying amount of each asset in the CGU. Any impairment loss for goodwill is recognized directly in the consolidated 
statement of earnings. An impairment loss for goodwill is not reversed in subsequent periods. 
On disposal of a subsidiary, the attributable amount of goodwill is included in the determination of the gain or loss on disposal.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

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21
2. CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS 
In connection with the preparation of the consolidated financial statements, the Group’s management has made assumptions 
and estimates about future events and applied judgments that affect the reported values of assets, liabilities, revenues, expenses 
and related disclosures. The assumptions, estimates and judgments are based on historical experience, current trends and other 
factors that management believes to be relevant at the time the consolidated financial statements are prepared. On a regular 
basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that the consolidated 
financial statements are presented fairly in accordance with IFRS Accounting Standards. However, because future events and 
their effects cannot be determined with certainty, actual results could differ from these assumptions and estimates, and such 
differences could be material.
Management believes the following critical accounting policies affect the more significant judgments and estimates used in the 
preparation of the consolidated financial statements:
Oil and gas reserves, impairment and asset retirement obligations
The accounting for oil and gas assets requires significant estimates and judgements, particularly in relation to reserves, impairment 
and asset retirement obligations. Estimates of proved and probable oil and gas reserves, prepared using standard recognized 
evaluation techniques and reviewed by independent qualified reserves auditors, are fundamental to impairment testing, 
depletion calculations under the unit of production method, and the timing and measurement of asset retirement obligations. 
These estimates are based on management’s assumptions regarding expected production volumes, future oil and gas prices, 
development and production costs, and economic factors as such oil price and inflation.
Impairment tests are performed when there are indicators of impairment. Key assumptions in the impairment models include oil 
and gas reserve estimates, forward price curves, long-term cost assumptions and the discount rate, all of which are subject to 
change as new information becomes available or economic conditions evolve.
Provisions for asset retirement obligations are based on estimates of future decommissioning and restoration costs, reflecting 
current legal and constructive requirements, available technology and prevailing price levels. Actual cash outflows may differ from 
estimates due to changes in legislation, technical requirements or cost levels, and therefore these provisions are reviewed on a 
regular basis.
Deferred income tax assets
The Group accounts for differences that arise between the carrying amount of assets and liabilities and their tax bases in 
accordance with IAS 12, Income Taxes, which requires deferred income tax assets only to be recognized to the extent that is 
probable that future taxable profits will be available against which the temporary differences can be utilized. Management
estimates future taxable profits based on the financial models used to value its oil and gas properties. Any change to the estimates 
and assumptions used for the key operational and financial variables used within the business models could affect the amount of 
deferred income tax assets recognized.
The effects of changes in estimates do not give rise to prior year adjustments and are treated prospectively over the estimated 
remaining commercial reserves of each field. While the Group uses its best estimates and judgement, actual results could differ 
from these estimates.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

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3. SEGMENT INFORMATION
The Group operates within several geographical areas. Operating segments are reported at a country level which is consistent with 
the internal reporting provided to the CEO, who is the chief operating decision maker.
The following tables present segment information regarding: revenue, production costs, other operating costs and gross profit/
(loss). The Group derives its revenue from contracts with customers primarily through the transfer of oil and gas at a point in time. 
In addition, certain identifiable asset segment information is reported in Note 8 and 9.
2025
USD Thousands Canada Malaysia France Other Total
Crude oil 589,415 66,330 46,301 – 702,046
NGLs 690 – – – 690
Gas 39,190 – – – 39,190
Sales of oil and gas 629,295 66,330 46,301 – 741,926
Change in under/over lift position – – 5,349 – 5,349
Royalties (83,229) – (2,976) – (86,205)
Hedging settlement 23,679 – – – 23,679
Other operating revenue – – 776 363 1,139
Revenue 569,745 66,330 49,450 363 685,888
Operating costs (217,059) (41,348) (33,962) – (292,369)
Cost of blending (134,630) – – – (134,630)
Change in inventory position (428) 247 (443) – (624)
Depletion and decommissioning costs (87,449) (24,194) (11,106) – (122,749)
Depreciation of other tangible fixed assets – (5,597) – – (5,597)
Exploration and business development costs – (698) (15) (1,086) (1,799)
Gross profit /(loss) 130,179 (5,260) 3,924 (723) 128,120
2024
USD Thousands Canada Malaysia France Other Total
Crude oil 678,094 105,445 70,948 – 854,487
NGLs 927 – – – 927
Gas 34,040 – – – 34,040
Sales of oil and gas 713,061 105,445 70,948 – 889,454
Change in under/over lift position – – 41 – 41
Royalties (111,114) – (4,285) – (115,399)
Hedging settlement 22,370 – – – 22,370
Other operating revenue – – 914 403 1,317
Revenue 624,317 105,445 67,618 403 797,783
Operating costs (225,775) (32,771) (35,464) – (294,010)
Cost of blending (152,735) – – – (152,735)
Change in inventory position (594) (1,024) 145 – (1,473)
Depletion and decommissioning costs (88,583) (27,481) (12,328) – (128,392)
Depreciation of other tangible fixed assets – (8,933) – – (8,933)
Exploration and business development costs – (1,407) (12) (650) (2,069)
Gross profit/(loss) 156,630 33,829 19,959 (247) 210,171
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

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23
USD Thousands
Assets Liabilities
2025 2024 2025 2024
Canada 2,129,806 2,010,107 1,329,423 1,226,081
Malaysia 156,911 165,701 125,376 104,290
France 169,609 158,518 91,082 83,581
Other 191,081 205,293 174,349 186,197
Intercompany balance elimination (669,778) (585,937) (669,778) (585,937)
Total Assets / Liabilities 1,977,629 1,953,682 1,050,452 1,014,212
Shareholders’ equity – – 927,029 939,315
Non-controlling interest – – 148 155
Total equity for the Group – – 927,177 939,470
Total consolidated 1,977,629 1,953,682 1,977,629 1,953,682
4. PRODUCTION COSTS
USD Thousands 2025 2024
Cost of operations 249,230 251,070 
Tariff and transportation expenses 38,752 38,195 
Direct production taxes 4,387 4,745 
Operating costs 292,369 294,010 
Cost of blending1 134,630 152,735 
Change in inventory position 624 1,473 
Total production costs 427,623 448,218 
1  In Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. Cost of blending represents the contracted 
purchase of diluent used for blending.
5. FINANCE INCOME
USD Thousands 2025 2024
Foreign exchange gain, net 14,654 –
Interest income 3,160 17,721
Other 274 –
Total finance income 18,088 17,721
6. FINANCE COSTS
USD Thousands 2025 2024
Foreign exchange loss, net – 12,654
Interest expense 41,983 35,905
Unwinding of asset retirement obligation discount 16,498 14,568
Amortization of capitalized financing fees 4,370 2,057
Loan commitment fees 894 837
Currency hedge losses 9,029 10,773
Other financial costs1 11,079 636
Total finance costs 83,853 77,430
1 Includes an amount of USD 9.8 million related to the call option costs of the previous USD 450 million senior unsecured bonds.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

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7. INCOME TAX
USD Thousands 2025 2024
Current tax (9) (8,313)
Deferred tax (17,371) (25,012)
Total tax expense (17,380) (33,325)
The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the tax rate of Canada as follows:
USD Thousands 2025 2024
Profit before tax 46,322 135,544
Tax calculated at the corporate tax rate in Canada 25% (11,581)  (33,886)
Effect of foreign and domestic tax rates 2,240 6,473
Tax effect of recognition / (derecognition) of unrecorded tax losses (8,253)  (6,216) 
Tax effect due to true-up of provision to prior year tax filings 368 790
Other (154) (486)
Total tax (17,380) (33,325)
Specification of deferred tax assets and tax liabilities1
USD Thousands 2025 2024
Unused tax loss carry forward 65,825  40,042 
Derivative hedges –  3,933 
Other 6,858  10,302
Deferred tax assets 72,683 54,277
Accelerated allowances 192,464  145,358
Derivative hedges 597 –
Deferred tax liabilities 193,061 145,358
Deferred taxes, net (120,378)  (91,081)
1  The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the 
balance sheet when they relate to the same jurisdiction.
The deferred tax liabilities consist of accelerated allowances, being the difference between the book and the tax value of oil and 
gas properties and site restoration provisions. The deferred tax liabilities will be released over the life of the oil and gas assets as 
the book value is depleted for accounting purposes. 
Deferred tax assets in relation to tax loss carried forwards are only recognized in so far that there is a reasonable certainty as to
the timing and the extent of their realization. The recognized unused tax loss carry forward mainly relates to Canada. The Group
has concluded that the deferred assets will be recoverable using the estimated future taxable income based on the approved
business plans and budgets.
Unrecognized tax losses
The Corporation has Canadian tax loss carry forwards of approximately USD 116 million (USD 92 million in 2024) and Dutch 
tax loss carry forwards of approximately USD 240 million (USD 240 million in 2024). The Canadian tax losses can be carried 
forward and utilized for up to 20 years and the Dutch tax losses can be carried forward indefinitely. A deferred tax asset of USD 
90 million (USD 84 million in 2024) relating to the tax loss carry forwards has not been recognized as at 31 December 2025 due 
to the uncertainty as to the timing and the extent of the tax loss carry forward utilisation. This treatment is consistent with the 
comparative year’s accounts.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

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8. EXPLORATION AND EVALUATION ASSETS
USD Thousands Canada Malaysia France Total
Cost
January 1, 2025 480 – – 480
Acquisitions 7,311 – – 7,311
Additions 5,036 – 15 5,051
Write-off – – (15) (15)
Reclassification (1,305) – – (1,305)
Currency translation adjustments 101 – – 101
Net book value December 31, 2025 11,623 – – 11,623
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 – – – –
Additions 500 1,407 12 1,919
Write-off – (1,407) (12) (1,419)
Currency translation adjustments (20) – – (20)
Net book value December 31, 2024 480 – – 480
9. PROPERTY, PLANT AND EQUIPMENT
USD Thousands 2025 2024
Oil and gas properties                 1,772,278    1,484,487
Other tangible fixed assets  11,220    16,425
Property, Plant and Equipment  1,783,498 1,500,912
Oil and gas properties
USD Thousands Canada Malaysia France Total
Cost
January 1, 2025 1,767,580 599,734 405,129 2,772,443
Additions 286,570 40,877 5,759 333,206
Change in estimates (9,845) (30) 1,959 (7,916)
Reclassification 1,305 – – 1,305
Currency translation adjustments 96,000 – 52,775 148,775
December 31, 2025 2,141,610 640,581 465,622 3,247,813
Accumulated depletion
January 1, 2025 (451,017) (530,315) (306,624) (1,287,956)
Depletion charge for the year (87,449) (24,194) (11,106) (122,749)
Currency translation adjustments (24,749) – (40,081) (64,830)
December 31, 2025 (563,215) (554,509) (357,811) (1,475,535)
Net book value December 31, 2025 1,578,395 86,072 107,811 1,772,278
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

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USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 1,465,010 591,123 436,693 2,492,826
Additions 412,284 17,035 3,475 432,794
Disposals (94) – – (94)
Change in estimates 36,995 (8,424) (9,018) 19,553
Reclassification (10,773) – – (10,773)
Currency translation adjustments (135,842) – (26,021) (161,863)
December 31, 2024 1,767,580 599,734 405,129 2,772,443
Accumulated depletion
January 1, 2024 (398,288) (502,834) (313,282) (1,214,404)
Depletion charge for the year (88,583) (27,481) (12,328) (128,392)
Disposals 94 – – 94
Currency translation adjustments 35,760 – 18,986 54,746
December 31, 2024 (451,017) (530,315) (306,624) (1,287,956)
Net book value December 31, 2024 1,316,563 69,419 98,505 1,484,487
  
                         
Impairment test
As of December 31, 2025, the Group determined that no internal or external indicators of impairment existed on its oil and gas
properties; therefore, the performance of an impairment test was determined not to be necessary (Similar as of December 31, 
2024).
     
Other tangible fixed assets
USD Thousands FPSO Other1 Total
Cost
January 1, 2025 204,853 9,824 214,677
Additions – 640 640
Disposals – (29) (29)
Currency translation adjustments – 812 812
December 31, 2025 204,853 11,247 216,100
Accumulated depreciation
January 1, 2025 (190,056) (8,196) (198,252)
Depreciation charge for the year (5,597) (397) (5,994)
Disposals – 29 29
Currency translation adjustments – (663) (663)
December 31, 2025 (195,653) (9,227) (204,880)
Net book value December 31, 2025 9,200 2,020 11,220
1  Depreciation of Other is included in General and administrative expenses in the statement of operations.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

===== SIDA 27 =====

27
USD Thousands FPSO Other1 Total
Cost
January 1, 2024 204,853 10,048 214,901
Additions – 363 363
Currency translation adjustments – (587) (587)
December 31, 2024 204,853 9,824 214,677
Accumulated depreciation
January 1, 2024 (181,123) (8,340) (189,463)
Depreciation charge for the year (8,933) (334) (9,267)
Currency translation adjustments – 478 478
December 31, 2024 (190,056) (8,196) (198,252)
Net book value December 31, 2024 14,797 1,628 16,425
1  Depreciation of Other is included in General and administrative expenses in the statement of operations.
The Floating Production Storage and Offloading facility (“FPSO“) located on the Bertam field, Malaysia, has been depreciated to its 
residual value. The depreciation charge is included in the depreciation of other assets line in the statement of operations.
For office equipment and other assets, the depreciation charge for the year is based on cost and an estimated useful life of 3 to 5 
years. The depreciation charge is included within the general and administrative expenses in the Statement of Operations.
10. RIGHT-OF-USE ASSETS AND LEASE LIABILITIES
USD Thousands Total
January 1, 2025 3,103
Additions 1,692
Depreciation (1,012)
Disposal (776)
Currency translation adjustments 63
Right-of-use-assets as at December 31, 2025 3,070
Current 930
Non-Current 2,956
Lease Liabilities as at December 31, 2025 3,886
USD Thousands Total
January 1, 2024 2,814
Additions 1,292
Depreciation (907)
Currency translation adjustments (96)
Right-of-use-assets as at December 31, 2024 3,103
Current 573
Non-Current 2,728
Lease Liabilities as at December 31, 2024 3,301
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED

===== SIDA 28 =====

28
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
11. OTHER NON-CURRENT ASSETS
USD Thousands December 31, 2025 December 31, 2024
Financial assets  34,545     34,788  
Intangible assets  11,671     13,877    
 46,216     48,665       
Financial assets mainly represent cash payments made in local currency to an asset retirement obligation fund for the Bertam 
field, Malaysia for an amount equivalent of USD 34.5 million (2024: USD 30.6 million). 
Intangible assets mainly represent carbon offsets purchased in Canada. 
12. INVENTORIES
USD Thousands December 31, 2025 December 31, 2024
Hydrocarbon stocks 11,995  11,250    
Well supplies and operational spares 7,995  8,823    
19,990  20,073    
13. TRADE AND OTHER RECEIVABLES
USD Thousands December 31, 2025 December 31, 2024
Trade receivables  73,245    94,265    
Underlift  6,704    1,007       
Joint operations debtors1  6,449    1,432    
Prepaid expenses and accrued income  8,437    12,346
Other  2,385    18,400 
 97,220    127,450    
1  Joint operations debtors include cash collateralized guarantees placed in respect of work commitments in Malaysia amounting to USD 4.0 million.
14. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include only cash at hand or held in bank accounts. 
15. SHARE CAPITAL
The Corporation’s issued common share capital is as follows:
Number of shares
Balance at January 1, 2024 126,992,066
Cancellation of repurchased common shares (7,822,595)
Balance at December 31, 2024 119,169,471
Cancellation of repurchased common shares (7,013,944)
Balance at December 31, 2025 112,155,527
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. The 
Corporation is authorized to issue an unlimited number of Common Shares without par value.
As at January 1, 2024, IPC had a total of 126,992,066 common shares issued and outstanding, with no common shares held in 
treasury.
During 2024, under the normal course issuer bid (NCIB) announced in December 2023 and renewed in December 2024, IPC 
purchased and cancelled an aggregate of 7,822,595 common shares.

===== SIDA 29 =====

29
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
As at January 1, 2025, IPC had a total of 119,169,471 common shares issued and outstanding, of which IPC held 110,156 common 
shares in treasury.
Over the period of January 1, 2025 to December 4, 2025, IPC purchased and cancelled 6,641,970 common shares under the 
normal course issuer bid (NCIB) and 261,818 common shares under certain other exemptions in Canada.
As at December 31, 2025, IPC had a total of 112,155,527 common shares issued and outstanding, with no common shares held in 
treasury.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares.
16. EARNINGS PER SHARE
Basic earnings per share are based on net result attributable to the common shareholders and is calculated based upon the 
weighted-average number of common shares outstanding during the years presented.
2025 2024
Net result attributable to shareholders of the Parent Company, USD  28,938,435 102,201,942
Weighted average number of shares for the year 114,915,700 124,072,452
Earnings per share, USD  0.25  0.82
Weighted average diluted number of shares for the year  116,916,203  126,299,688
Earnings per share fully diluted, USD 0.25 0.81
17. SHARE BASED PAYMENTS
IPC Share Unit Plan
The shareholders of IPC at the 2018 Annual General Meeting and at the 2021 Annual General Meeting approved a Share Unit Plan.
Awards under the plan will be accounted from the date of grant.
The IPC Performance Share Plan (“PSP”) 2022 awards vested on February 1, 2025 at a price of CAD 18.89 per award.
The IPC PSP 2023 awards are subject to continued employment and to certain performance conditions being met. The total 
outstanding number of awards at December 31, 2025, is 813,000 which vested on February 1, 2026 at a price of CAD 27.18. Each 
award was fair valued at the grant date at CAD 11.51 using an adjusted share price calculated with a hybrid valuation model based 
on the Monte Carlo simulation. The assumptions used in the calculation of the adjusted share price were a risk free rate of 2.17%, 
expected volatility of 46%, dividend yield rate of 0%, and an exercise price of CAD zero.
The IPC PSP 2024 awards are subject to continued employment and to certain performance conditions being met. The total 
outstanding number of awards at December 31, 2025, is 819,000 which vest on February 1, 2027. Each award was fair valued 
at the grant date at CAD 11.52 using an adjusted share price calculated with a hybrid valuation model based on the Monte Carlo 
simulation. The assumptions used in the calculation of the adjusted share price were a risk free rate of 2.27%, expected volatility 
of 39%, dividend yield rate of 0%, and an exercise price of CAD zero.
The IPC PSP 2025 awards are subject to continued employment and to certain performance conditions being met. The total 
outstanding number of awards at December 31, 2025, is 597,000 which vest on February 1, 2028. Each award was fair valued 
at the grant date at CAD 14.03 using an adjusted share price calculated with a hybrid valuation model based on the Monte Carlo 
simulation. The assumptions used in the calculation of the adjusted share price were a risk free rate of 2.19%, expected volatility 
of 34%, dividend yield rate of 0%, and an exercise price of CAD zero.

===== SIDA 30 =====

30
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
IPC Performance Share Plan 2022 Awards 2023 Awards 2024 Awards 2025 Awards Total
Outstanding at January 1, 2025  937,000  813,000  819,000 –  2,569,000 
Awarded during the year – – –  597,000  597,000 
Forfeited during the year – – – – –
Vested during the year (937,000) – – – (937,000)
Outstanding at December 31, 2025 –  813,000  819,000  597,000  2,229,000 
Vesting date
February 1, 2026 –  813,000 – –  813,000 
February 1, 2027 – –  819,000 –  819,000 
February 1, 2028 – – –  597,000  597,000 
Outstanding at December 31, 2025 –  813,000  819,000  597,000  2,229,000 
The third instalment of the IPC Restricted Share Plan (“RSP”) 2022 awards vested on February 1, 2025, at a price of CAD 18.89 
per award.
The second instalment of the IPC RSP 2023 awards vested on February 1, 2025, at a price of CAD 18.89 per award. The total 
outstanding number of 2023 awards under the IPC RSP as at December 31, 2025, is 104,098 which vested on February 1, 2026, at 
a price of CAD 27.18. Each award was fair valued at the grant date at CAD 14.27.
The first instalment of the IPC RSP 2024 awards vested on February 1, 2025, at a price of CAD 18.89 per award. The second 
instalment of the IPC RSP 2024 vested on February 1, 2026, at a price of CAD 27.18. The third instalment vests on February 1, 
2027, subject to continued employment. Each award was fair valued at the grant date at CAD 14.82.
The first instalment of the IPC RSP 2025 awards vested on February 1, 2026, at a price of CAD 27.18 per award. The second and 
third instalment vest respectively on February 1, 2027, and February 1, 2028, subject to continued employment. Each award was 
fair valued at the grant date at CAD 18.90.
IPC Restricted Share Plan 2022 Awards 2023 Awards 2024 Awards 2025 Awards Total
Outstanding at January 1, 2025  151,035  217,080  364,035 –  732,150 
Awarded during the year – – – 337,154  337,154 
Forfeited during the year (2,381) (4,423) (10,849) – (17,653) 
Vested during the year (148,654) (108,559) (121,515) – (378,728) 
Outstanding at December 31, 2025 – 104,098 231,671 337,154  672,923 
Vesting date
February 1, 2026 –  104,098  115,836  112,385  332,319 
February 1, 2027 – –   115,835  112,385 228,220
February 1, 2028 – – –  112,384  112,384
Outstanding at December 31, 2025 –  104,098  231,671  337,154  672,923 
Under the IPC Share Unit Plan, the Group allows non-employee directors of the Corporation to elect for awards for fees for 
services performed as a director and otherwise payable in cash. These awards will vest immediately at the time of grant. However, 
these awards may not be redeemed before the end of service as a director of the Corporation. The 2021 outstanding RSP awards 
as at December 31, 2025 is 4,333 awards issued with a fair value at the grant date at CAD 6.95. The 2022 outstanding RSP awards 
as at December 31, 2025 is 2,391 awards issued with a fair value at the grant date at CAD 12.80, and 2,072 awards issued with a 
fair value at the grant date at CAD 15.53. The 2023 outstanding RSP awards as at December 31, 2025 is 3,244 awards issued with 
a fair value at the grant date at CAD 10.52, and 2,443 awards issued with a fair value at the grant date at CAD 16.24. The 2024 
outstanding RSP awards as at December 31, 2025 is 4,328 awards issued with a fair value at the grant date at CAD 18.20, and 
5,607 awards issued with a fair value at the grant date at CAD 15.72. The 2025 outstanding RSP awards as at December 31, 2025 
is 3,795 awards issued with a fair value at the grant date at CAD 22.02, and 3,404 awards issued with a fair value at the grant date 
at CAD 24.66. The total outstanding RSP awards outstanding as at December 31, 2025, is 31,617.

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

31
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
The costs charged to the statement of operations of the Group for the Share-Based payments are summarized in the following 
table:
USD Thousands 2025 2024
IPC PSP – 2021 Awards – 108
IPC RSP – 2021 Awards – 52
IPC PSP – 2022 Awards  125 1,477
IPC RSP – 2022 Awards  14 464
IPC PSP – 2023 Awards  1,723 1,728
IPC RSP – 2023 Awards  387 1,048
IPC PSP – 2024 Awards  1,832 1,414
IPC RSP – 2024 Awards  1,134 2,248
IPC PSP – 2025 Awards  1,762 –
IPC RSP – 2025 Awards  2,461 –
 9,348 8,539
18. FINANCIAL LIABILITIES
USD Thousands December 31, 2025 December 31, 2024
Current bank loans 1,943 3,402
Non current bank loans 38,709 1,719
Bonds 450,000 443,407
Capitalized financing fees (7,676) (3,545) 
482,976 444,983
As at January 1, 2025, IPC had USD 450 million of senior unsecured bonds outstanding, maturing in February 2027 with a fixed 
coupon rate of 7.25% per annum. In October 2025, IPC completed the issuance of USD 450 million of new senior unsecured 
bonds, maturing in October 2030 with a fixed coupon rate of 7.50% per annum, payable in semi-annual instalments in April and 
October, and with semi-annual amortizations of USD 25 million commencing in April 2028. The  proceeds of the new bonds were 
used to fully redeem and cancel the previous bonds. IPC exercised its call option to redeem the previous bonds at a price equal to 
102.18% of the nominal amount, plus accrued and unpaid interest. The cash refinancing costs, which include the call option costs 
of the senior unsecured bonds, and the related transaction costs, incurred in Q4 2025, amounted USD 18.3 million.
The bond repayment obligations as at December 31, 2025, are classified as non-current as there are no mandatory repayments 
within the next twelve months.
In addition, as at December 31, 2025, the Group had a senior secured revolving credit facility of CAD 250 million (the “Canadian 
RCF”) in connection with its oil and gas assets in Canada, with a maturity date in May 2027. As at December 31, 2025, CAD 53 
million (approximately USD 39 million) was drawn under the Canadian RCF . As at December 31, 2025, the Group also had a letter 
of credit facility in Canada (the “LC Facility”) to cover operational letters of credit. As at December 31, 2025, operational letters of 
credit in an aggregate of CAD 19.7 million have been issued under the LC Facility, of which one letter of credit of CAD 5.3 million 
was fully released in January 2026.
As at December 31, 2025, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May
2026. IPC makes quarterly repayments of the France Facility and the amount remaining outstanding under the France Facility as 
at December 31, 2025 was USD 1.9 million (EUR 1.7 million) which is classified as current representing the repayment planned 
within the next twelve months.
The Group is in compliance with the covenants of the bonds and its financing facilities as at December 31, 2025.

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

32
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
The net (debt)/cash reconciliation can be summarized as follows:
USD Thousands December 31, 2025 December 31, 2024
Cash and cash equivalents 7,037 246,593    
Bonds (450,000)  (443,407) 
Borrowings (40,652) (5,121)    
Lease liabilities (3,886) (3,301)
Net (debt)/cash (487,501) (205,236)  
The net (debt)/cash and the movements in net (debt)/cash can be summarized as follows:
USD Thousands Cash Lease
liabilities
Financial 
liabilities due 
before 1 year
Financial 
liabilities due 
after 1 year
Bonds due 
after 1 year Total
Net (debt)/cash as at January 1, 2025 246,593 (3,301) (3,402) (1,719) (443,407) (205,236)
Cash flows (226,702) 976 3,178 (38,709) (6,593) (267,850)
Reclassification Long term / Short term – – (1,719) 1,719 – –
Additional leases – (1,492) – – – (1,492)
Currency translation adjustments (12,854) (69) – – – (12,923)
Net (debt)/cash as at December 31, 2025 7,037 (3,886) (1,943) (38,709) (450,000) (487,501)
Net debt (excluding lease liabilities) (483,615)
USD Thousands Cash Lease
liabilities
Financial 
liabilities due 
before 1 year
Financial 
liabilities due 
after 1 year
Bonds due 
after 1 year Total
Net (debt)/cash as at January 1, 2024 517,074 (2,896) (3,589) (5,442) (440,288) 64,859
Cash flows (275,871) 964 – 3,910 (3,119) (274,116)
Reclassification Long term / Short term – – 187 (187) – –
Additional leases – (1,480) – – – (1,480)
Currency translation adjustments 5,390 111 – – – 5,501
Net (debt)/cash as at December 31, 2024 246,593 (3,301) (3,402) (1,719) (443,407) (205,236)
Net debt (excluding lease liabilities and 
including the redeemable bonds value 
at maturity (USD 450 million)) 
(208,528)

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

33
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
19. PROVISIONS
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2025 267,790 1,679 3,685 2,072 275,226
Additions – – 816 815 1,631
Unwinding of asset retirement obligation discount 16,498 – – – 16,498
Payments (5,967) (587) (963) (897) (8,414)
Change in estimates (7,916) – (654) – (8,570)
Reclassification1 725 – – – 725
Currency translation adjustments 13,402 138 488 107 14,135
December 31, 2025 284,532 1,230 3,372 2,097 291,231
Non-current 278,733 – 3,372 2,097 284,202
Current 5,799 1,230 – – 7,029
Total 284,532 1,230 3,372 2,097 291,231
1 The reclassification of the asset retirement obligation related to the 2025 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 11). 
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2024 253,949 2,176 551 2,078 258,754
Additions – – 682 544 1,226
Disposals (197) – – – (197)
Unwinding of asset retirement obligation discount 14,568 – – – 14,568
Payments (7,711) (591) (906) (500) (9,708)
Change in estimates 19,553 – 3,491 – 23,044
Reclassification1 1,013 – – – 1,013
Currency translation adjustments (13,385) 94 (133) (50) (13,474)
December 31, 2024 267,790 1,679 3,685 2,072 275,226
Non-current 261,632 1,120 3,685 2,072 268,509
Current 6,158 559 – – 6,717
Total 267,790 1,679 3,685 2,072 275,226
1 The reclassification of the asset retirement obligation related to the 2024 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 11). 
The farm-in obligation relates to future payments for historic costs on the Bertam field in Malaysia payable for every 1 MMboe 
gross that the field produces above 10 MMboe gross and is capped at cumulative production of 27.5 MMboe gross. 
In calculating the present value of the asset retirement obligation provision, a blended discount rate of 6% (2024: 6%) per annum 
was used, based on a credit risk adjusted rate. The calculation also assumes that the costs are inflated by  2% a year (2024: 2%) 
The payment of these obligations is spread over a period of 60 years.

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

34
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
20. PENSION LIABILITY
The Group operates a pension plan for employees in Switzerland that is managed through a private pension plan. The amount 
recognized in the balance sheet associated with the Swiss pension plan is as follows:
USD Thousands December 31, 2025 December 31, 2024
Present value of defined benefit obligation 23,135 19,569
Fair value of plan assets (19,763) (15,884)
Pension obligation, ending balance 3,372 3,685
The movement in the defined benefit obligation over the year is as follows:
USD Thousands For the year ended
December 31, 2025
For the year ended
December 31, 2024
Opening balance 19,569 22,241
Current service cost 758 608
Ordinary contributions paid by employees 642 604
Additional contributions paid by employees 1,425 1,340
Interest expense on defined benefit obligation 213 402
Actuarial (gain)/loss on defined benefit obligation (402) 3,390
Administration costs 19 18
Benefits paid from plan assets (1,920) (7,440)
Past service cost – 46
Foreign exchange (gain)/loss 2,831 (1,640)
Defined benefit obligation, ending balance 23,135 19,569
The weighted average duration of the defined benefit obligation is 15.56 years. There is no maturity profile since the average 
remaining life before active employees reach final age according to the plan is 9.04 years.
The movement in the fair value of the plan assets over the year is as follows:
USD Thousands For the year ended
December 31, 2025
For the year ended
December 31, 2024
Opening balance 15,884 21,690
Ordinary contributions paid by employer 962 906
Ordinary contributions paid by employees 642 604
Additional contributions paid by employees 1,425 1,340
Interest income on plan assets 173 392
Return on plan assets excluding interest income 252 (101)
Foreign exchange gain/(loss) 2,345 (1,507)
Benefits paid from plan assets (1,920) (7,440)
Fair value of plan assets, ending balance 19,763 15,884
The plan assets are under an insurance contract comprised entirely of free funds and reserves, such as fluctuation reserves and 
employer contribution reserves, for which there is no quoted price in an active market.
The amount recognized in the statement of operations associated with the Group’s pension plan is as follows:
USD Thousands For the year ended
December 31, 2025
For the year ended
December 31, 2024
Current service cost 758 608
Interest expense on defined benefit obligation 213 402
Administration costs 19 18
Past service cost – 46
Interest income on plan assets (173) (392)
Total expense recognized 817 682

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

35
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
The expense associated with the Group’s pension plan of USD 817 thousand was included within general and administrative 
expenses. The Group also recognized in other comprehensive income a USD 654 thousand net actuarial gain on defined benefit 
obligations and pension plan assets.  
The principal actuarial assumptions used to estimate the Group’s pension obligation are as follows:
USD Thousands
For the year ended
December 31, 2025
For the year ended
December 31, 2024
Discount rate 1.30% 1.00%
Inflation rate 0.90% 1.00%
Future salary increase 1.25% 1.25%
Future pension increases 0.00% 0.00%
Retirement ages, male (‘M’) and female (‘F’) M65/F65 M65/F65
Assumptions regarding future mortality are set based on actuarial advice in accordance with the BVG 2020 GT generational 
published statistics and experience in Switzerland. The discount rate is determined by reference to the yield on high quality 
corporate bonds. The rate of inflation is based on the expected value of future annual inflation adjustments in Switzerland. The rate 
for future salary increases is based on the average increase in the salaries paid by the Group, and the rate of pension increases is 
based on the annual increase in risk, retirement and survivors’ benefits. 
The sensitivity of the defined benefit obligation to changes in the weighted principal assumptions is:
Change in
assumption
Increase in
assumption
Decrease in
assumption
Discount rate 0.50% Decrease by 7.1% Increase by 8.1%
Salary growth rate 0.50% Increase by 0.4% Decrease by 0.4%
Life Expectancy One year Increase by 1.3% Decrease by 1.3%
The above sensitivity analyses are based on a change in an assumption while holding all other assumptions constant. In practice, 
this is unlikely to occur, and changes in some of the assumptions may be correlated. When calculating the sensitivity of the 
defined benefit obligation to significant actuarial assumptions, the same method has been applied as when calculating the pension 
liability recognized within the consolidated balance sheet.
21. TRADE AND OTHER PAYABLES
USD Thousands December 31, 2025 December 31, 2024
Trade payables 39,377  42,634    
Joint operations creditors 9,141  11,671    
Accrued expenses 94,410  119,316    
Other 6,780  2,750    
149,708  176,371    
22. FINANCIAL ASSETS AND LIABILITIES
Financial assets and liabilities by category
The accounting policies for financial instruments have been applied to the line items below:
December 31, 2025
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 34,545 34,545 – –
Derivative instruments 2,929 – – 2,929
Joint operation debtors 6,449 6,449 – –
Other current receivables2 86,745 80,041 6,704 –
Cash and cash equivalents 7,037 7,037 – –
Financial assets 137,705 128,072 6,704 2,929
1 See Note 11
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.

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

36
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
December 31, 2025
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 481,033 481,033 – –
Current financial liabilities 1,943 1,943 – –
Derivative instruments 422 – – 422
Joint operation creditors 9,141 9,141 – –
Other current liabilities 140,783 140,783 – –
Financial liabilities 633,322 632,900 – 422
December 31, 2024
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 34,788 34,788 – –
Derivative instruments 3,219 – – 3,219
Joint operation debtors 1,432 1,432 – –
Other current receivables2 115,186 114,179 1,007 –
Cash and cash equivalents 246,593 246,593 – –
Financial assets 401,218 396,992 1,007 3,219
1 See Note 11
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
December 31, 2024
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 441,581 441,581 – –
Current financial liabilities 3,402 3,402 – –
Derivative instruments 20,431 – – 20,431
Joint operation creditors 11,671 11,671 – –
Other current liabilities 165,846 165,846 – –
Financial liabilities 642,931 622,500 – 20,431
The carrying amount of the Group’s financial assets and liabilities approximate their fair values at the balance sheet dates.
 For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
  – Level 1: based on quoted prices in active markets;
  – Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
  – Level 3: based on inputs which are not based on observable market data.

===== SIDA 37 =====

37
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
December 31, 2025
USD Thousands Level 1 Level 2 Level 3
Other current receivables 6,704 – –
Derivative instruments – current – 1,644 –
Derivative instruments – non-current – – 1,285
Financial assets 6,704 1,644 1,285
Derivative instruments – current – – –
Derivative instruments – non-current – – 422
Financial liabilities – – 422
December 31, 2024
USD Thousands Level 1 Level 2 Level 3
Other current receivables 1,007 – –
Derivative instruments – current – 3,219 –
Derivative instruments – non-current – – –
Financial assets 1,007 3,219 –
Derivative instruments – current – 19,869 –
Derivative instruments – non-current – – 562
Financial liabilities – 19,869 562
23. MANAGEMENT OF FINANCIAL RISK
The Corporation’s financial instruments are exposed to certain financial risks, including credit risk, liquidity risk, foreign exchange 
risk, commodity price risk and interest rate risk. 
a) Credit risk
The exposure to credit risk arises through the failure of a customer or another third party to meet its contractual obligations to the 
Corporation. The Corporation believes that its maximum exposure to credit risk as at December 31, 2025, is the carrying value of 
its trade receivables. The Group’s policy is to limit credit risk by limiting the counterparties to major oil and gas companies. Where 
it is determined that there is a credit risk for oil and gas sales, the policy is to require an irrevocable letter of credit for the full value 
of the sale. The policy on joint operation parties is to rely on the provisions of the underlying joint operating agreements to take 
possession of the licence or the partner’s share of production for non-payment of cash calls or other amounts due.
As at December 31, 2025, the trade receivables amounted to USD 73,245 thousand and there is no recent history of default. The 
expected credit loss associated with these receivables is not significant. Cash and cash equivalents are maintained with banks 
having strong long-term credit ratings.
b) Liquidity risk 
Liquidity risk is defined as the risk that the Group could not be able to settle or meet its obligations on time or at a reasonable 
price. Corporation treasury is responsible for liquidity, funding as well as settlement management. The Corporation has in 
place a planning and forecasting process to help determine the funds required to support the Corporation’s normal operating 
requirements on an ongoing basis. The Corporation ensures that there is sufficient available capital to meet its short-term business 
requirements, taking into account its anticipated cash flows from operations and its holdings of cash and cash equivalents, 
including bond proceeds. The Corporation has credit facilities in place to assist with meeting its cash flow needs as required (Note 
18).
The table below analyses the Group’s financial liabilities into relevant maturity groupings based on the remaining period at the 
balance sheet date to the contractual maturity date. Loan repayments are made upon a net present value calculation of the assets’ 
future cash flows. No loan repayments are currently forecast under this calculation.

===== SIDA 38 =====

38
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
USD Thousands December 31, 2025 December 31, 2024
Non-current  
Repayment within 1- 5 years:
  - Bank loans 38,709 1,719
  - Bonds 450,000 443,407
  - Lease liabilities 2,956 2,728
491,665 447,854
Current
Repayment within 12 months:
 - Bank loans 1,943 3,402
Payment within 6 months:
  - Trade payables 39,377 42,634
  - Joint operation creditors 9,141 11,671
  - Other current liabilities 6,780 2,750
  - Lease liabilities 930 573
  - Current tax liabilities 216 1,146
58,387 62,176
c) Foreign exchange risk 
The Group operates internationally and is exposed to foreign exchange risk arising from various currencies, primarily with respect 
to EUR and CAD. The Group’s risk management objective is to manage cash flow risk related to foreign denominated cash flows. 
The Corporation is exposed to currency risk related to changes in rates of exchange between foreign denominated balances and 
the functional currencies of the Group’s principal operating subsidiaries. The Group’s revenues are denominated in US dollars, 
while most of its operating and capital expenditures are denominated in the local currencies. A significant change in the currency 
exchange rates between the US dollar and foreign currencies could have a material effect on the Group’s net earnings and on other 
comprehensive income.
The Group has no outstanding currency hedges as of December 31, 2025:
Fair value of outstanding derivative instruments in the balance sheet
USD Thousands
December 31, 2025 December 31, 2024
Assets Liabilities Assets Liabilities
Currency hedge - CAD – – – 19,030
Currency hedge - EUR – – – 557
Currency hedge - MYR – – – 282
Total – – – 19,869
Non-current – – – –
Current – – – 19,869
Total – – – 19,869

===== SIDA 39 =====

39
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
The following tables summarize the effects that changes in currencies against the US Dollar would have on gross profit through the 
conversion of the income statements of the Group’s subsidiaries from functional currency to the presentation currency US Dollar for 
the years ended at December 31, 2025 and 2024.
Shift of currency exchange rates
USD Thousands
Average rate
2025
USD weakening
10%
USD strengthening 
10%
Gross profit in the financial statements 128,120 128,120
EUR/USD 0.8855 0.8050 0.9741
CAD/USD 1.3975 1.2705 1.5373
Total effect on gross profit 13,072 (13,072)
Shift of currency exchange rates
USD Thousands
Average rate
2024
USD weakening
10%
USD strengthening 
10%
Gross profit in the financial statements 210,171 210,171
EUR/USD 0.9241 0.8401 1.0170
CAD/USD 1.3698 1.2453 1.5068
Total effect on gross profit 17,054 (17,054)
 
d) Commodity price risk 
The Group is subject to price risk associated with fluctuations in the market prices for oil and gas. Prices of oil and gas are affected by 
the normal economic drivers of supply and demand as well as the financial investors and market uncertainty. Factors that influence 
these include operational decisions, natural disasters, economic conditions, political instability or conflicts or actions by major oil 
exporting countries. Price fluctuations can affect the Corporation’s financial position.
Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in the price of oil and natural gas. 
Commodity prices are impacted by world economic events that affect supply and demand, which are generally beyond the Group’s 
control. Changes in crude oil prices may significantly affect the Corporation’s results of operations, cash generated from operating 
activities, capital spending and the Corporation’s ability to meet its obligations. The majority of the Corporation’s production is sold 
under short-term contracts; consequently the Group is at risk to near term price movements. The Corporation manages this risk by 
constantly monitoring commodity prices and factoring them into operational decisions, such as contracting or expanding its capital 
expenditures program. 
The Corporation enters into certain risk management contracts in order to manage the exposure to market risks from fluctuations 
in commodity prices. These risk management contracts are not used for trading or speculative purposes. The Corporation has 
designated its risk management contracts as effective accounting hedges, and thus has applied hedge accounting. As a result, all 
risk management contracts are recorded at fair value at each reporting period with the change in fair value being recognized on the 
statement of comprehensive income.

===== SIDA 40 =====

40
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
The Group had oil price sale financial hedges outstanding as at December 31, 2025, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
January 1, 2026 - December 31, 2026 5,000 WTI/WCS Differential USD -12.50/bbl
The Group had gas price sale financial hedges outstanding as at December 31, 2025 which are summarized as follows:
Period Volume (Gigajoules (GJ) per 
day)) Type Average Pricing 
April 1, 2026 - October 31, 2026 15,000 AECO Swap CAD 2.73/GJ
The Group had electricity financial hedges outstanding as at December 31, 2025, which are summarized as follows:
Period Volume (MW) Type Average Pricing 
January 1, 2026 - September 30, 2040 3 AESO CAD 75.00/MWh
All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
The outstanding derivative instruments can be specified as follows:
Fair value of outstanding derivative instruments in the balance sheet:
USD Thousands
December 31, 2025 December 31, 2024
Assets Liabilities Assets Liabilities
Oil price hedge 710 – 1,949 –
Gas price hedge 934 – 1,270 –
Electricity price hedge 1,285 422 – 562
Total 2,929 422 3,219 562
Non-current – – – 562
Current 2,929 422 3,219 –
Total 2,929 422 3,219 562
The table below summarizes the effect that a change in the oil and gas price would have had on the net result at December 31, 2025 
and 2024:
2025 net result (USD Thousands) 28,942 28,942
Possible shift (%) (10%) 10%
Total effect on net result (USD Thousands) (54,369) 54,369
2024 net result (USD Thousands) 102,219 102,219
Possible shift (%) (10%) 10%
Total effect on net result (USD Thousands) (65,653) 65,653
e) Interest rate risk 
The Group’s exposure to interest rate risk arises from the impact of interest rate fluctuations on its debt facilities. As at December 
31, 2025, the Group’s long-term debt primarily consists of senior unsecured bonds bearing a fixed coupon rate of 7.5%, as well as 
a senior secured revolving credit facility subject to a variable interest rate, which ranged between 5.29% and 6.7% during the year 
2025. As a result, changes in interest rates are not expected to have a significant adverse impact on the Group’s interest expense.

===== SIDA 41 =====

41
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
24. MANAGEMENT OF CAPITAL RISK
The objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its 
committed work program requirements in order to create shareholder value. The Corporation may put in place new credit facilities, 
repay debt, or other such restructuring activities as appropriate. Management continuously monitors and manages the capital and 
liquidity position in order to assess the requirement for changes to the capital structure to meet the objectives and to maintain 
flexibility. 
No significant changes were made in the objectives, policies or procedures during the year ended December 31, 2025 or in the 
comparative years.
Through the ongoing management of its capital, the Corporation will modify the structure of its capital based on changing 
economic conditions in the jurisdictions in which it operates. In doing so, the Corporation may issue new shares or debt, buy back 
issued shares, or pay off any outstanding debt.
25. SALARY AND OTHER COMPENSATION EXPENSES
a) Employee benefits expense
The total employee benefits expense for the year ended December 31, 2025, amounted to USD 84,078 thousand (2024: USD 68,897 
thousand).
b) Remuneration of Directors and Senior Management
Remuneration of Directors and Senior Management includes all amounts earned and awarded to the Group’s Board of Directors 
and Senior Management. Senior Management includes the Group’s President and Chief Executive Officer, Chief Financial 
Officer, Chief Operating Officer, General Counsel and Corporate Secretary, Senior Vice President Corporate Planning and Investor 
Relations, Senior Vice President Canada, Vice President Asset Management and Corporate Planning Canada, and Vice President 
Commercial Canada.
Directors’ fees include Board and Committee fees. Senior Management’s remuneration includes salary, short-term benefits, 
bonuses and any other compensation earned is as follows: 
USD Thousands 2025 2024
Directors’ fees 900 900
Senior Management’s salaries, bonuses and other short-term benefits 7,130 6,196
Share-based incentive plans paid to Senior Management 7,138 10,114
15,168 17,210
26. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In the normal course of business, the Group has committed to certain payments which are not recognized as liabilities. The 
following table summarizes the Group’s commitments in Canada as at December 31, 2025:
CAD Millions 2026 2027 2028 2029 2030 Thereafter
Transportation service1  60.4    91.6 99.1 103.1 103.9 1,384.7
Power2 12.4 12.4 9.8 –     –     –  
Total commitments 72.8 104.0 108.9 103.1 103.9 1,384.7
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2046.
2  IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from January 1, 2026 - December 
31, 2028 and an additional 5MWh at a weighted average price of CAD 58.31/MWh from January 1, 2026 to December 31, 2027.
27. RELATED PARTIES
The Group recognizes the following related parties: associated companies, jointly controlled entities, key management personnel 
and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or 
of its family or of any individual that controls, or has joint control or significant influence over the entity.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with 
parties at arm’s length.
During 2025, the Group has not entered into material transactions with related parties.

===== SIDA 42 =====

42
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025 and 2024, AUDITED
28. SUBSEQUENT EVENTS
In January 2026, the Group entered into the following oil price sale financial hedges:                         
Period Volume (barrels per day) Type Average Pricing 
February 1, 2026 - June 30, 2026 5,000 WTI Sale Swap USD 60.04/bbl
February 1, 2026 - June 30, 2026 2,500 WTI Sale Swap USD 64.50/bbl
February 1, 2026 - June 30, 2026 1,500 Brent Sale Swap USD 66.67/bbl

===== SIDA 43 =====

International Petroleum Corporation
Suite 2800
1055 Dunsmuir Street
Vancouver, British Columbia
V7X 1L2, Canada
Tel: +1 604 689 7842
E-mail: info@international-petroleum.com
Web: international-petroleum.com□

===== SIDA 44 =====

Q4
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three months and year ended December 31, 2025

===== SIDA 45 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Contents
Non-IFRS Measures
References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization”  
(EBITDA), “operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under IFRS Accounting Standards (“IFRS”) and do 
not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF, FCF, EBITDA, operating costs and net debt/
net cash that may be used by other public companies. Management believes that OCF, FCF, EBITDA, operating costs and net debt/net cash are useful supplemental 
measures that may assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Non-IFRS 
measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS 
measure is presented in this MD&A. See “Non-IFRS Measures” on page 21.
Forward-Looking Statements
Certain statements contained in this MD&A constitute “forward-looking statements” or “forward-looking information” (within the meaning of applicable securities 
legislation). Such statements and information (together, “forward-looking statements”) relate to future events, including the Corporation’s future performance, 
business prospects or opportunities. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, 
forecasts, guidance, budgets, 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“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, “might“, “should“, “believe“, 
“budget“ and similar expressions) are not statements of historical fact and may be “forward-looking statements“. Although IPC believes that the expectations and 
assumptions on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because 
IPC can give no assurances that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they  
involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. For additional 
information underlying forward-looking statements, refer to the “Cautionary Statement Regarding Forward-Looking Information” on page 36.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada and France/Malaysia are 
effective as of December 31, 2025, and are included in the reports prepared by Sproule International Limited and ERCE Equipoise Ltd., respectively (collectively, 
Sproule ERCE), an independent qualified reserves evaluator and auditor, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas 
Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule ERCE’s December 31, 2025, price forecasts.
Certain abbreviations and technical terms used in this MD&A are defined or described under the heading “Other Supplementary Information”.
INTRODUCTION  3
HIGHLIGHTS  4
OPERATIONS REVIEW  6
• Business Overview 6
• Operations Overview  9
FINANCIAL REVIEW  11
• Financial Results 11
• Capital Expenditure 20
• Financial Position and Liquidity  20
• Non-IFRS Measures 21
• Off-Balance Sheet Arrangements  23
• Outstanding Share Data  23
• Contractual Obligations and Commitments  23
• Material Accounting Policies and Estimates 24
• Transactions with Related Parties  24
• Financial Risk Management  24
RISK FACTORS 26
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING  36
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION  36
RESERVES AND RESOURCES ADVISORY  39
OTHER SUPPLEMENTARY INFORMATION 41
2

===== SIDA 46 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
INTRODUCTION
This management’s discussion and analysis (“MD&A”) for International Petroleum Corporation (“IPC” or the “Corporation” and, 
together with its subsidiaries, the “Group”) is dated February 10, 2026 and is intended to provide an overview of the Group’s 
operations, financial performance and current and future business opportunities. This MD&A should be read in conjunction with 
IPC’s audited consolidated financial statements and accompanying notes for the year ended December 31, 2025 (“Financial 
Statements”).
Group Overview
The Group is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production 
assets and development projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in 
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada, under the Business Corporations Act. The 
address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is 
Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
Basis of Preparation
The MD&A and the Financial Statements have been prepared in accordance with IFRS Accounting Standards (“IFRS”) as issued by 
the International Accounting Standards Board (“IASB”). 
Financial information is presented in United States Dollars (“USD”). However, as the Group operates in Europe and in Canada, 
certain financial information prepared by subsidiaries has been reported in Euros (“EUR”) and in Canadian Dollars (“CAD”). In 
addition, certain costs relating to the operations in Malaysia, which are reported in USD, are incurred in Malaysian Ringgit (“MYR”). 
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
December 31, 2025 December 31, 2024
Average Year end Average Year end
1 EUR equals USD 1.1293 1.1750 1.0821 1.0389
1 USD equals CAD 1.3975 1.3692 1.3698 1.4388
1 USD equals MYR 4.2791 4.0580 4.5759 4.4715
              
3

===== SIDA 47 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
HIGHLIGHTS
2025 Business Highlights
• Average net production of approximately 45,600 boepd for the fourth quarter of 2025 was in line with the guidance range for 
the period (52% heavy crude oil, 15% light and medium crude oil and 33% natural gas).(1)
• Full year 2025 average net production was 44,900 boepd, at the high end of the 2025 annual guidance of 43,000 to 45,000 
boepd.(1)
• Development activities on Phase 1 of the Blackrod project progressed in 2025 ahead of schedule and on budget, with first 
steam injection achieved in Q4 2025 and forecast first oil in Q3 2026. 
• Completed the acquisition of lands adjacent to the Blackrod project, adding 64 MMboe of contingent resources (best 
estimate, unrisked).(1)(2)
• At Onion Lake Thermal, Canada, four production infill wells and the final Pad L sustaining well pair were brought online by Q3 
2025.
• Successfully completed the drilling and workover program at the Bertam Field, Malaysia during Q3 2025.
• 7.7 million IPC common shares purchased and cancelled from December 2024 to early December 2025.
• In Q3 2025, published IPC’s sixth annual Sustainability Report.
2025 Financial Highlights
• Operating costs per boe of USD 18.4 for the fourth quarter of 2025 and USD 17.8 for the full year, below the low end of the 
2025 guidance of USD 18.0 to 19.0 per boe.(3)
• Strong operating cash flow (OCF) generation for the fourth quarter and full year 2025 amounted to MUSD 63 and MUSD 
259, respectively.(3)
• Capital and decommissioning expenditures of MUSD 63 for the fourth quarter and MUSD 344 for the full year 2025, in line 
with the latest full year guidance.
• Free cash flow (FCF) generation for the full year 2025 of negative MUSD 153, with negative MUSD 29 for the fourth quarter 
in line with expectations. FCF for the full year 2025, before 2025 Blackrod capital expenditure of MUSD 256, was MUSD 
103.(3)
• Net debt of MUSD 484 as at December 31, 2025. (3)
• Net result of negative MUSD 5 for the fourth quarter of 2025 and positive MUSD 29 for the full year 2025.
• Amended and extended IPC’s MCAD 250 revolving credit facility in Q2 2025, extending the maturity to May 2027.
• Refinanced IPC’s MUSD 450 unsecured bonds in Q4 2025, extending the maturity to October 2030.
Reserves and Resources
• Total 2P reserves as at December 31, 2025 of 521 MMboe, with a reserve life index (RLI) of 31 years and a reserves 
replacement ratio of 277%.(1)(2)
• Proved developed producing (PDP) reserves increase of 28% from year-end 2024 to year-end 2025 to 125 MMboe, primarily 
driven from Blackrod Phase 1.(1)(2) 
• Contingent resources (best estimate, unrisked) as at December 31, 2025 of 1,224 MMboe. (1)(2)
2026 Annual Guidance
• Full year 2026 average net production forecast at 44,000 to 47,000 boepd. (1)
• Full year 2026 operating costs forecast at USD 18 to 20 per boe. (3)
• Full year 2026 OCF estimated at between MUSD 100 and 250 (assuming Brent USD 55 to 75 per barrel). (3)
• Full year 2026 capital and decommissioning expenditures guidance forecast at MUSD 122.
• Full year 2026 FCF forecast ranges from approximately negative MUSD 70 to positive MUSD 85 (assuming Brent USD 55 to 
75 per barrel).(3)
Current Business Plan FCF Forecasts
• Cumulative forecast FCF of approximately MUSD 1,000 to 2,000 over the period of 2026 to 2030 and approximately MUSD 
700 to 1,600 over the period of 2031 to 2035 (assuming Brent USD 65 to 85 per barrel). (3)(7)
4

===== SIDA 48 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Three months ended 
December 31
Year ended 
December 31
USD Thousands 2025 2024 2025 2024
Revenue 176,207 199,124 685,888 797,783 
Gross profit 28,242 42,774 128,120 210,171 
Net result (4,941) 415 28,942 102,219 
Operating cash flow(3) 63,138 78,158 258,903 341,989 
Free cash flow(3) (28,627) (61,476) (153,134) (135,497)
EBITDA(3) 58,966 76,184 243,537 335,488 
Net cash/(debt)(3) (483,615) (208,528) (483,615) (208,528)
5

===== SIDA 49 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
OPERATIONS REVIEW 
Business Overview
International Petroleum Corporation is an entrepreneurially driven company that seeks to maximise shareholder value through 
responsible business operations and accretive growth. IPC started in 2017 with 113.5 million common shares outstanding and a 
debt-free portfolio of high-quality producing assets in Malaysia, France and the Netherlands, hosting combined 2P reserves of 29 
MMboe, production of 10 Mboepd, a reserve life index of 8 years and a NPV10 of USD 0.5 billion.  
This platform acted as a springboard for IPC to carry out countercyclical strategic moves including building a position in Canada 
through acquisitions and sanctioning a major Steam Assisted Gravity Drainage (SAGD) greenfield development project. The 
decisive moves undertaken by the company have been grounded by taking a long-term view and increasing exposure to oil. We 
are very pleased to see the positive market recognition in Canadian E&Ps, validating the bold decisions made to enter and grow in 
the jurisdiction given the vast resource and favourable fiscal terms.  
As IPC enters its tenth year of existence in 2026, excluding the Blackrod Phase 1 growth capital expenditures, over USD 1.6 
billion in free cash flow (FCF) has been generated and our current common shares outstanding is less than the starting amount 
at approximately 112.2 million shares. Current 2P reserves are 18 times higher standing at 521 MMboe and contingent resources 
(best estimate, unrisked) have grown from 0 MMboe in 2017 to now greater than 1,200 MMboe. Our reserve life index is four 
times higher at 31 years based on our 2026 mid-point production guidance of 45.5 Mboepd. Production is expected to grow to 
greater than 65 Mboepd by 2028 which underpins material FCF per share growth in the years ahead.(1)(2)(3)
Oil prices in 2025 ranged from Brent USD 59 to 77 per barrel, with a full year Brent averaging USD 69 per barrel compared to USD 
81 per barrel averaged over the previous year 2024. The fourth quarter 2025 Brent price averaged USD 64 per barrel. The volatility 
in benchmark oil prices during 2025 was largely due to changing US economic and tariff policies and the corresponding potential 
effects on global economic growth, continuing geopolitical conflicts, and concerns regarding oil oversupply including from releases 
of OPEC production curtailments. IPC believes that these short-term uncertainties will lead to underinvestment in the industry, 
which combined with continued projected record breaking annual global oil demand into 2026 and beyond, should have a positive 
effect on oil prices at a time when IPC is ramping up Blackrod Phase 1 production.
IPC has hedged 1,500 barrels per day of forecast 2026 oil production at around USD 67 per barrel for Dated Brent and 7,500 
barrels per day of forecast 2026 oil production at around USD 61.5 per barrel for West Texas Intermediate (WTI).
The fourth quarter 2025 WTI to Western Canadian Select (WCS) price differential averaged USD 11 per barrel, in line with the full 
year 2025 average. The WTI to WCS differential continues to benefit from the TMX pipeline expansion, driving up competitive 
tension for Canadian oil and increased buying from Asia. The outlook of the WTI to WCS differential remains tight with excess 
egress capacity relative to the supply in the Western Canadian Sedimentary Basin (WCSB), balanced against the potential of 
Venezuelan heavy oil barrels to the US Gulf Coast PADD III refineries. There are currently no tariffs on Canadian crude oil exports 
to the United States, which remain covered by the US Mexico Canada trade agreement. For 2026, IPC has implemented WTI to 
WCS differential hedges for 5,000 barrels per day at USD -12.50 per barrel.
The average Canadian gas benchmark price, AECO, was CAD 2.16 per Mcf for the fourth quarter of 2025 and CAD 1.63 for the 
full year 2025. WCSB gas inventory levels remain elevated above the historical average. There is an expectation for storage levels 
to draw during the winter period, with very cold weather experienced in North America in early 2026 and further supported by the 
ramp up of the LNG Canada project in 2026 which should drive higher natural gas prices in Canada. IPC has implemented hedges 
for 15,000 GJ per day at CAD 2.73 per GJ for 2026 from April to October 2026.
Fourth Quarter and Full Year 2025 Highlights
During the fourth quarter of 2025, IPC’s assets delivered average net production of 45,600 boepd, in line with guidance for the 
quarter. Full year 2025 average net production of 44,900 boepd was the high end of the 2025 guidance range of 43,000 to 45,000 
boepd.(1)
IPC’s operating costs per boe for the fourth quarter of 2025 was USD 18.4. Full year 2025 operating costs per boe was USD 17.8, 
below the low end of the 2025 annual guidance of USD 18.0 to 19.0 per boe.(3)
Operating cash flow (OCF) generation for the fourth quarter of 2025 was USD 63 million. Full year 2025 OCF was USD 259 million 
above the most recent Q3 2025 guidance of USD 245 to 255 million.(3)
Capital and decommissioning expenditure for the fourth quarter of 2025 was USD 63 million. Full year 2025 capital and 
decommissioning expenditure of USD 344 million was in line with latest guidance of USD 340 million.
Free cash flow (FCF) generation was in line with guidance at negative USD 29 million during the fourth quarter of 2025. Full year 
2025 FCF generation was negative USD 153 million, better than the most recent guidance of negative USD 160 to 170 million.(3)
As at December 31, 2025, IPC’s net debt position was USD 484 million. IPC prudently refinanced its USD 450 million of unsecured 
bonds in Q4 2025, extending maturity to October 2030. IPC also has access to a revolving credit facility of CAD 250 million, with 
approximately CAD 200 million undrawn as at the end of 2025.(3)
6

===== SIDA 50 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Blackrod
The Blackrod asset is 100% owned by IPC and hosts the largest booked reserves and contingent resources within the IPC 
portfolio. After more than a decade of pilot operations, subsurface delineation and commercial engineering studies, IPC sanctioned 
the Phase 1 SAGD development in the first quarter of 2023. The Phase 1 development targets 311 MMboe of 2P reserves, with a 
multi-year forecast capital expenditure of USD 850 million to first oil planned in Q3 2026. The Phase 1 development is planned for 
plateau production of 30,000 bopd which is expected by the end of 2027.(1)(2)
As previously announced, IPC achieved first steam at the Blackrod Phase 1 project in December 2025, a quarter earlier than 
originally guided. By the end of 2025, USD 820 million of cumulative growth capital has been spent on the Blackrod Phase 1 
development since sanction. Construction is nearing completion at the central processing facility (CPF), commissioning activities 
are ongoing, and drilling plus completions continue to track favourably. Site health and safety control has been excellent with no 
material safety incidents since commercial development activities commenced.
Approximately USD 30 million of growth capital budget remains to reach first oil at Blackrod Phase 1 in 2026. IPC is well-positioned 
to deliver in line with the multi-year budget of USD 850 million to first oil. The total growth capital expenditure comprises the total 
installed costs for the facilities and associated 40 well pairs needed to fill the plant capacity of 30,000 bopd and has remained 
unchanged since the time of sanction in 2023.(1)
The remaining capital expenditure planned to be spent at Blackrod in 2026 of approximately USD 60 million includes acceleration 
of sustaining capital, taking advantage of economies of scale and the positive momentum seen by the drilling rig at site, capitalised 
operations for the operating costs incurred prior to first oil, and resource maturation works.  
Blackrod realised a material uplift in recoverable resource through 2025 through a combination of favourable drilling results within 
and outside of the initial development area and further supplemented by acquiring adjacent lands with 64 MMboe of contingent 
resources (best estimate, unrisked). The 2P reserves attributable to Phase 1 has increased by 52 MMboe to 311 MMboe from 
year-end 2024 to year-end 2025. The contingent resources (best estimate, unrisked) attributed to the Blackrod asset realised a net 
increase of 117 MMboe to 1,142 MMboe.(1)(2) 
Stakeholder Returns: Normal Course Issuer Bid
During the period of December 5, 2024 to December 4, 2025, IPC purchased and cancelled an aggregate of approximately 7.7 
million common shares under the 2024/2025 NCIB and certain other exemptions in Canada. The average price of shares purchased 
under the 2024/2025 NCIB was SEK 144 / CAD 20 per share.
Since inception, IPC has returned over USD 600 million in shareholder returns in the form of share buybacks, cancelling over 77 
million common shares at an aggregate average share price of around SEK 79 / CAD 11 per share. Since 2022, more than 27% of 
the shares outstanding have been repurchased and cancelled. 
In Q4 2025, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 6.5 million common 
shares over the period of December 5, 2025 to December 4, 2026. IPC remains focused on progressing the Blackrod Phase 1 
development project first oil and will continue to monitor commodity prices in 2026 before acquiring IPC common shares under 
the current NCIB.
As at December 31, 2025 and February 10, 2026, IPC had a total of 112,155,527 common shares issued and outstanding and IPC 
holds no common shares in treasury.
Environmental, Social and Governance (ESG) Performance
As part of IPC’s commitment to operational excellence and responsible development, IPC’s objective is to reduce risk and 
eliminate hazards to prevent occurrence of accidents, ill health, and environmental damage, as these are essential to the success 
of our business operations. During the fourth quarter and for the full year 2025, IPC recorded no material safety or environmental 
incidents.
As previously announced, IPC targeted a reduction of our net GHG emissions intensity by the end of 2025 to 50% of IPC’s 2019 
baseline and IPC is on track to achieve this reduction for 2025 net GHG emissions intensity. IPC is committed to remain at end 
2025 levels of 20 kg CO2/boe through to the end of 2028.(4)
Reserves, Resources and Value
As at the end of December 2025, IPC’s 2P reserves are 521 MMboe. During 2025, IPC replaced 277% of the annual 2025 
production. The reserve life index (RLI) as at December 31, 2025, is approximately 31 years.(1)(2)
The net present value (NPV) of IPC’s 2P reserves as at December 31, 2025 was around USD 2.7 billion. The net asset value (NAV) 
of IPC’s 2P reserves as at December 31, 2025 was around USD 2.2 billion. Based on IPC’s current business plans, the cumulative 
forecast FCF is approximately MUSD 1,000 to 2,000 over the period of 2026 to 2030 and approximately MUSD 700 to 1,600 over 
the period of 2031 to 2035 (assuming Brent USD 65 to 85 per barrel).(1)(2)(5)(6)(7)
In addition, IPC’s best estimate contingent resources (unrisked) as at December 31, 2025 are 1,224 MMboe, of which 1,142 
MMboe relate to future potential phases of the Blackrod project.(1)(2)
7

===== SIDA 51 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
2026 Budget and Operational Guidance
IPC is pleased to announce its 2026 average net production guidance is 44,000 to 47,000 boepd. IPC forecasts operating costs for 
2026 between USD 18 and 20 per boe.(1)(3)
IPC’s 2026 capital and decommissioning expenditure budget is USD 122 million, with USD 90 million forecast relating to Blackrod 
capital expenditure. The remainder of the 2026 budget relates mainly to routine maintenance and ongoing optimization work at 
the other producing assets. In all of IPC’s areas of operation, IPC has significant flexibility to control its pace of spend based on the 
development of commodity prices during 2026.
Further details regarding IPC’s proposed 2026 budget and operational guidance will be provided at IPC’s Capital Markets Day 
presentation to be held on February 10, 2026 at 15:00 CET. A copy of the Capital Markets Day presentation will be available on 
IPC’s website at www.international-petroleum.com.
Notes:
(1) See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory” below. See also the 
material change report (MCR) available on IPC’s website at www.international-petroleum.com and filed on the date of this 
press release under IPC’s profile on SEDAR+ at www.sedarplus.ca.
 
(2) See “Reserves and Resources Advisory“ below. Further information with respect to IPC’s reserves, contingent resources 
and estimates of future net revenue, including assumptions relating to the calculation of NPV, are described in the MCR. 
The reserve life index (RLI) is calculated by dividing the 2P reserves of 521 MMboe as at December 31, 2025 by the 
mid-point of the 2026 CMD production guidance of 44,000 to 47,000 boepd. Reserves replacement ratio is based on 2P 
reserves of 493 MMboe as at December 31, 2024, sales production during 2025 of 15.7 MMboe, net additions to 2P 
reserves during 2025 of 43.4 MMboe, and 2P reserves of 521 MMboe as at December 31, 2025.
(3) Non-IFRS measure, see “Non-IFRS Measures” below.
(4) Emissions intensity is the ratio between oil and gas production and the associated carbon emissions, and net emissions 
intensity reflects gross emissions less operational emission reductions and carbon offsets.
(5) Net present value (NPV) is after tax, discounted at 10% and based upon the forecast prices and other assumptions further 
described in the MCR. See “Reserves and Resources Advisory” below.
(6) Net asset value (NAV) is calculated as NPV less net debt of USD 484 million as at December 31, 2025.
(7) Estimated FCF generation is based on IPC’s current business plans over the periods of 2026 to 2030 and 2031 to 
2035, including net debt of USD 484 million as at December 31, 2025, with assumptions based on the reports of IPC’s 
independent reserves evaluator and auditor, and including certain corporate adjustments relating to estimated general 
and administration costs and hedging, and excluding shareholder distributions and certain refinancing costs. Assumptions 
include average net production of approximately 62 Mboepd over the period of 2026 to 2030, average capital expenditures 
of approximately USD 5 per boe, average operating costs of approximately USD 18 to 20 per boe, average Brent oil 
prices of USD 65 to 85 per bbl escalating by 2% per year, and average Brent to Western Canadian Select differentials 
and average gas prices as estimated by IPC’s independent reserves evaluator and auditor and as further described in 
the MCR. Estimated FCF generation at Brent oil prices of USD 95 per barrel escalating by 2% per year, based on the 
same assumptions set out above, are approximately MUSD 2,500 and 2,100 for the same periods, respectively. IPC’s 
market capitalization is at close on February 2, 2026 (USD 2,277 million based on 182 SEK/share, 112.2 million IPC shares 
outstanding and exchange rate of 8.97 SEK/ USD). IPC’s current business plans and assumptions, and the business 
environment, are subject to change. Actual results may differ materially from forward-looking estimates and forecasts. See 
“Forward-Looking Statements” and “Non-IFRS Measures” below.
8

===== SIDA 52 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Operations Overview 
2025 Overview
In 2025, IPC continued to successfully demonstrate its commitment to operational excellence, delivering high end production 
performance with strong cost discipline resulting in operating expenditure at the low end of our Capital Markets Day (CMD) 
guidance. No material safety or environmental incidents were recorded in the year.
The Blackrod Phase 1 development delivered first steam ahead of schedule, with the remaining project scope and the overall 
project budget continuing to progress in line with guidance. The warm-up process, through steam circulation, for the initial set of 
wells is ongoing and IPC continues to forecast first oil production from Blackrod Phase 1 in Q3 2026. Remaining central processing 
facility construction (CPF) handover and progressive commissioning is on track. Final construction works and commissioning of 
the CPF is ongoing, with additional well pairs scheduled for steam circulation in Q2 2026. Drilling of the final well pad commenced 
in Q4 2025 and is ongoing. To take advantage of the economies of scale and to provide additional well capacity, IPC plans to 
drill sixteen well pairs on the final pad, providing six additional sustaining well pairs beyond the original budget of the Phase 1 
development. As of the end of Q4 2025, the fuel gas input line is in service and supporting well steam circulation operations. Final 
third-party export pipeline commissioning is progressing in line with plan with only minor work remaining ahead of all three lines 
being operational. 
At Onion Lake Thermal in Canada, the four 2025 drilled production infill wells and the ninth and final Pad L sustaining well pair are 
online with continued production performance ahead of expectations.
In Malaysia, field development studies continued in Q4 2025 on the back of the successful A21 drilling and A15 well workover 
which was finalized in Q3 2025.
In France, field development studies continued in Q4 2025. The next three well sidetrack drilling targets at the Fontaine-au-Bron 
have been matured and are ready for sanction decision at the company’s discretion.
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 521 MMboe as at December 31, 2025, as certified by independent 
third party reserve auditors. The 2P reserve life index (RLI) as at December 31, 2025, is approximately 31 years. Best estimate 
contingent resources as at December 31, 2025, are 1,224 MMboe (unrisked). See “Reserves and Resources Advisory” below.
Production
Average daily net production for Q4 2025 was at IPC’s high end CMD guidance at 45,600 boepd. In Canada, strong operational 
performance has been supplemented by recent production infill well drilling at Onion Lake Thermal. Stable performance continued 
at IPC’s Malaysian and French assets.
With strong operational delivery through 2025, IPC exits the year with a net average daily production for 2025 at the high end of 
our CMD guidance at 44,900 boepd.
The production during Q4 2025 with comparatives is summarized below:
Production
in Mboepd
Three months ended
December 31
Year ended
December 31
2025 2024 2025 2024
Crude oil
Canada – Northern Assets 15.4 14.6 14.7 14.2
Canada – Southern Assets 9.6 11.2 10.2 11.1
Malaysia 3.4 3.5 3.0 3.8
France 2.1 2.1 2.1 2.4
Total crude oil production 30.5 31.4 30.0 31.5
Gas
Canada – Northern Assets 0.4 0.5 0.4 0.5
Canada – Southern Assets 14.7 15.5 14.5 15.4
Total gas production 15.1 16.0 14.9 15.9
Total production 45.6 47.4 44.9 47.4
Quantity in MMboe 4.19 4.36 16.38 17.34
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
9

===== SIDA 53 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
CANADA
Production
in Mboepd
Working 
Interest
(WI)
Three months ended
December 31
Year ended
December 31
2025 2024 2025 2024
- Oil Onion Lake Thermal 100% 12.7 12.2 12.2 12.3
- Oil Suffield Area 100% 8.5 9.8 8.9 9.7
- Oil Other 50-100% 3.7 3.8 3.8 3.3
- Gas ~100% 15.1 16.0 14.9 15.9
Canada 40.0 41.8 39.8 41.2
Production
Net production from IPC’s assets in Canada during Q4 2025 was ahead of guidance at 40,000 boepd with continued strong 
operational performance at the major oil and gas producing assets. At Onion Lake Thermal, recent production infill well drilling 
contributed to strong production rates during the quarter. At Mooney, the Phase 2 polymer flood project continues to deliver ahead 
of expectations.
MALAYSIA
Production
in Mboepd WI
Three months ended
December 31
Year ended
December 31
2025 2024 2025 2024
Bertam 100% 3.4 3.5 3.0 3.8
Production
Net production at Bertam in Malaysia in Q4 2025 was in line with guidance at 3,400 boepd. Planned maintenance shutdown 
activity was completed on time and in line with budget in early Q4 2025.
FRANCE
Production
in Mboepd WI
Three months ended
December 31
Year ended
December 31
2025 2024 2025 2024
France
- Paris Basin 100%1 1.7 1.8 1.8 2.1
- Aquitaine 50% 0.3 0.3 0.3 0.3
2.0 2.1 2.1 2.4
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q4 2025 was in line with guidance at 2,000 boepd with stable performance across all the major 
producing fields. 
  
10

===== SIDA 54 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
FINANCIAL REVIEW 
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands 2025 2024 2023
Revenue 685,888 797,783 853,906
Gross profit 128,120 210,171 250,514
Net result 28,942 102,219 172,979
Earnings per share – USD 0.25 0.82 1.31
Earnings per share fully diluted – USD 0.25 0.81 1.28
Operating cash flow1 258,903 341,989 353,048
Free cash flow1 (153,134) (135,497) 2,689
EBITDA1 243,537 335,488 350,618
Net cash / (debt) at period end1 (483,615) (208,528) 58,043
1 See definition on page 21 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands December 31, 2025 December 31, 2024 December 31, 2023
Non-current assets 1,847,327 1,554,833 1,372,388
Current assets 130,302 398,849 690,597
Total assets 1,977,629 1,953,682 2,062,985
Total non-current liabilities 890,204 806,134 779,838
Current liabilities 160,248 208,078 202,888
Total liabilities 1,050,452 1,014,212 982,726
Net assets 927,177 939,470 1,080,259
Working capital (including cash) (29,946) 190,771 487,709
11

===== SIDA 55 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Selected Interim Financial Information
Selected interim condensed consolidated statement of operations is as follows:
USD Thousands 2025 Q4-25 Q3-25 Q2-25 Q1-25 2024 Q4-24 Q3-24 Q2-24 Q1-24
Revenue 685,888 176,207 172,297 158,892 178,492 797,783 199,124 173,200 219,040 206,419
Gross profit 128,120 28,242 32,066 23,663 44,149 210,171 42,774 39,505 72,708 55,184
Net result 28,942 (4,942) 3,802 13,850 16,231 102,219 415 22,875 45,210 33,719
Earnings per share – 
USD 0.25 (0.04) 0.03 0.12 0.14 0.82 0.00 0.19 0.36 0.27
Earnings per share fully
diluted – USD 0.25 (0.04) 0.03 0.12 0.13 0.81 0.00 0.18 0.36 0.26
Operating cash flow1 258,903 63,138 66,102 54,873 74,790 341,989 78,158 72,589 101,941 89,301
Free cash flow1 (153,134) (28,627) (23,083) (58,252) (43,172) (135,497) (61,476) (38,269) 7,559 (43,311)
EBITDA1 243,537 58,966 62,106 51,519 70,946 335,488 76,184 68,313 103,971 87,020
Net cash/(debt) at 
period end1 (483,615) (483,615) (434,822) (374,977) (314,255) (208,528) (208,528) (157,228) (88,220) (60,572)
1 See definition on page 21 under “Non-IFRS measures”
Selected Interim Financial Information
The Group operates within several geographical areas. Operating segments are reported at a country level, with Canada being 
further analyzed by main areas: (i) Canada – Northern Assets (comprising mainly of the Onion Lake Thermal asset) and (ii) Canada –
Southern Assets (comprising mainly of the Suffield assets, including the Brooks assets). This is consistent with the internal 
reporting provided to the CEO, who is the chief operating decision maker. The following tables present certain segment 
information.
Three months ended – December 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 86,933 46,004 23,545 10,154 – 166,636
NGLs – 155 – – – 155
Gas 108 13,078 – – – 13,186
Net sales of oil and gas 87,041 59,237 23,545 10,154 – 179,977
Change in under/over lift 
position – – – 1,064 – 1,064
Royalties (11,807) (5,808) – (473) – (18,088)
Hedging settlement 7,274 5,659 – – – 12,933
Other operating revenue – – – 204 117 321
Revenue 82,508 59,088 23,545 10,949 117 176,207
Operating costs (28,727) (29,076) (10,091) (9,173) – (77,067)
Cost of blending (26,822) (4,362) – – – (31,184)
Change in inventory position 3 (65) (5,622) (16) – (5,700)
Depletion and decommissioning 
costs (9,952) (12,076) (7,048) (3,091) – (32,167)
Depreciation of other tangible 
fixed assets – – (800) – – (800)
Exploration and business
development costs – – (698) (15) (334) (1,047)
Gross profit/(loss) 17,010 13,509 (714) (1,346) (217) 28,242
12

===== SIDA 56 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Three months ended – December 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 96,884 63,453 29,675 21,039 – 211,051
NGLs – 165 – – – 165
Gas 69 8,990 – – – 9,059
Net sales of oil and gas 96,953 72,608 29,675 21,039 – 220,275
Change in under/over lift position – – – (6,379) – (6,379)
Royalties (14,048) (10,690) – (821) – (25,559)
Hedging settlement 5,430 5,012 – – – 10,442
Other operating revenue – – – 244 101 345
Revenue 88,335 66,930 29,675 14,083 101 199,124
Operating costs (23,554) (35,573) (9,386) (10,926) – (79,439)
Cost of blending (29,653) (6,383) – – – (36,036)
Change in inventory position (741) 434 (4,750) 424 – (4,633)
Depletion and decommissioning 
costs (9,141) (12,960) (7,273) (2,713) – (32,087)
Depreciation of other tangible 
fixed assets – – (2,430) – – (2,430)
Exploration and business
development costs – – (1,407) (12) (306) (1,725)
Gross profit/(loss) 25,246 12,448 4,429 856 (205) 42,774
Year ended – December 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 370,788 218,627 66,330 46,301 – 702,046
NGLs – 690 – – – 690
Gas 312 38,878 – – – 39,190
Net sales of oil and gas 371,100 258,195 66,330 46,301 – 741,926
Change in under/over lift position – – – 5,349 – 5,349
Royalties (51,128) (32,101) – (2,976) – (86,205)
Hedging settlement 10,553 13,126 – – – 23,679
Other operating revenue – – – 776 363 1,139
Revenue 330,525 239,220 66,330 49,450 363 685,888
Operating costs (90,400) (126,659) (41,348) (33,962) – (292,369)
Cost of blending (114,087) (20,543) – – – (134,630)
Change in inventory position 146 (574) 247 (443) – (624)
Depletion and decommissioning 
costs (37,994) (49,455) (24,194) (11,106) – (122,749)
Depreciation of other tangible 
fixed assets – – (5,597) – – (5,597)
Exploration and business
development costs – – (698) (15) (1,086) (1,799)
Gross profit/(loss) 88,190 41,989 (5,260) 3,924 (723) 128,120
13

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

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Year ended – December 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 405,090 273,004 105,445 70,948 – 854,487
NGLs – 927 – – – 927
Gas 264 33,776 – – – 34,040
Net sales of oil and gas 405,354 307,707 105,445 70,948 – 889,454
Change in under/over lift position – – – 41 – 41
Royalties (67,613) (43,501) – (4,285) – (115,399)
Hedging settlement 12,096 10,274 – – – 22,370
Other operating revenue – – – 914 403 1,317
Revenue 349,837 274,480 105,445 67,618 403 797,783
Operating costs (84,018) (141,757) (32,771) (35,464) – (294,010)
Cost of blending (126,936) (25,799) – – – (152,735)
Change in inventory position (4) (590) (1,024) 145 – (1,473)
Depletion and decommissioning 
costs (36,554) (52,029) (27,481) (12,328) – (128,392)
Depreciation of other tangible 
fixed assets – – (8,933) – – (8,933)
Exploration and business
development costs – – (1,407) (12) (650) (2,069)
Gross profit/(loss) 102,325 54,305 33,829 19,959 (247) 210,171
Three months and year ended December 31, 2025, Review 
Revenue
Total revenue amounted to USD 176,207 thousand for Q4 2025, compared to USD 199,124 thousand for Q4 2024 and USD
685,888 thousand for the year ended December 31, 2025 compared to USD 797,783 thousand for the year ended December 31, 
2024 and is analyzed as follows: 
USD Thousands 
Three months ended 
December 31
Year ended
December 31
2025 2024 2025 2024
Crude oil sales 166,636 211,051 702,046 854,487
Gas and NGL sales 13,341 9,224 39,880 34,967
Change in under/overlift position 1,064 (6,379) 5,349 41
Royalties (18,088) (25,559) (86,205) (115,399)
Hedging settlement 12,933 10,442 23,679 22,370
Other operating revenue 321 345 1,139 1,317
Total revenue 176,207 199,124 685,888 797,783
14

===== SIDA 58 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
The main components of total revenue for the three months and year ended December 31, 2025, and December 31, 2024, 
respectively, are detailed below. 
Crude oil sales
Three months ended – December 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 86,933 46,004 23,545 10,154 166,636
- Quantity sold in bbls 1,833,241 957,670 347,943 158,369 3,297,223
- Average price realized USD per bbl 47.42 48.04 67.67 64.12 50.54
Three months ended – December 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 96,884 63,453 29,675 21,039 211,051
- Quantity sold in bbls 1,715,195 1,088,790 379,569 284,053 3,467,607
- Average price realized USD per bbl 56.49 58.28 78.18 74.07 60.86
Crude oil revenue was 21% lower in Q4 2025 compared to Q4 2024 mainly due to lower prices. Canadian-Northern Assets sales 
volumes are 7% higher in Q4 2025 compared to Q4 2024 as a result of sustaining capital investment activities undertaken at 
Onion Lake Thermal. 
The Suffield area assets and Onion Lake Thermal crude oil in Canada is blended with purchased condensate diluent volumes 
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for 
Canada.
The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q4 2025, WTI averaged USD 59 per bbl compared to USD 70 per bbl for Q4 2024 and the 
average discount to WCS used in IPC’s pricing formula was USD 11 per bbl compared to USD 13 per bbl for the comparative 
period in 2024.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There were two cargo liftings in Malaysia 
during Q4 2025 and two cargo liftings in Q4 2024. Produced unsold oil barrels from Bertam at the end of Q4 2025 amounted to 
106,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 64 per bbl for 
Q4 2025 compared to USD 75 per bbl for the comparative period in 2024.
Year ended – December 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 370,788 218,627 66,330 46,301 702,046
- Quantity sold in bbls 6,986,416 4,044,356 928,010 665,536 12,624,318
- Average price realized USD per bbl 53.07 54.06 71.48 69.57 55.61
Year ended – December 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 405,090 273,004 105,445 70,948 854,487
- Quantity sold in bbls 6,727,693 4,442,570 1,224,980 886,766 13,282,009
- Average price realized USD per bbl 60.21 61.45 86.08 80.01 64.33
15

===== SIDA 59 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
The Suffield area assets and Onion Lake crude oil in Canada is blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for 
Canada.
Crude oil revenue was lower by 18% during 2025 compared to 2024 due to oil prices lower by 14% and sales volume lower by 
5%.
The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. For the year ended December 31, 
2025, WTI averaged USD 65 per bbl compared to USD 76 per bbl for the comparative period and the average discount to WCS 
used in our pricing formula was USD 11 per bbl compared to USD 15 per bbl for the comparative period.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices and the average market Brent crude oil 
price was USD 69 per bbl for the year ended December 31, 2025 compared to USD 81 per bbl for the comparative period.
Gas and NGL sales
Three months ended – December 31, 2025
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 108 13,233 13,341
- Quantity sold in Mcf 75,328 7,715,625 7,490,953
- Average price realized USD per Mcf 1.43 1.78 1.78
Three months ended – December 31, 2024
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 69 9,155 9,224
- Quantity sold in Mcf 76,102 7,791,291 7,867,393
- Average price realized USD per Mcf 0.91 1.18 1.17
Gas and NGL sales revenue was 45% higher for the Q4 2025 compared to Q4 2024 due to the higher achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For Q4 2025, IPC realized an average price of CAD 2.46 per 
Mcf compared to AECO average pricing of CAD 2.16 per Mcf.
Year ended – December 31, 2025
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 312 39,568 39,880
- Quantity sold in Mcf 287,570 29,027,623 29,315,193
- Average price realized USD per Mcf 1.08 1.36 1.36
Year ended – December 31, 2024
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 264 34,703 34,967
- Quantity sold in Mcf 284,209 30,601,443 30,885,652
- Average price realized USD per Mcf 0.93 1.13 1.13
Gas and NGL sales revenue was 14% higher for 2025 compared to 2024 mainly due to the higher achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For the year ended December 31, 2025, IPC realized an 
average price of CAD 1.87 per Mcf compared to AECO average pricing of CAD 1.63 per Mcf.
16

===== SIDA 60 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Hedging settlement
IPC enters into oil and gas prices risk management contracts in order to ensure a certain level of cash flow. It focuses mainly 
on oil and gas price swaps and on collars to a lesser extent, to mitigate these commodities price exposure. Oil and gas hedging 
contracts are not entered into for speculative purposes and only account for a portion of our production.
The realized hedging settlement for the year ended December 31, 2025 amounted to a gain of USD 23,679 thousand and 
consisted of a gain of USD 17,869 thousand on the oil contracts and a gain of USD 5,810 thousand on the gas contracts. Also see 
the Financial Position and Liquidity and the Financial Risk Management sections below.
Production costs
Production costs including inventory movements amounted to USD 113,951 thousand for Q4 2025 compared to USD 120,108 
thousand for Q4 2024 and USD 427,623 thousand for the full year 2025 compared to USD 448,218 thousand for the full year 2024, 
and is analyzed as follows:
Three months ended – December 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 28,727 29,076 10,091 9,173 – 77,067
USD/boe2 19.75 13.02 31.95 48.50 n/a 18.38
Cost of blending 26,822 4,362 – – – 31,184
Change in inventory position (3) 65 5,622 16 – 5,700
Production costs 55,546 33,503 15,713 9,189 – 113,951
Three months ended – December 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 23,554 35,573 13,418 10,926 (4,032) 79,439
USD/boe2 17.04 14.47 41.31 55.91 n/a 18.21
Cost of blending 29,653 6,383 – – – 36,036
Change in inventory position 741 (434) 4,750 (424) – 4,633
Production costs 53,948 41,522 18,168 10,502 (4,032) 120,108
Year ended – December 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 90,400 126,659 44,876 33,962 (3,528) 292,369
USD/boe2 16.36 14.07 41.40 43.83 n/a 17.84
Cost of blending 114,087 20,543 – – – 134,630
Change in inventory position (146) 574 (247) 443 – 624
Production costs 204,341 147,776 44,629 34,405 (3,528) 427,623
17

===== SIDA 61 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Year ended – December 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 84,018 141,757 49,089 35,464 (16,318) 294,010
USD/boe2 15.74 14.60 34.85 40.13 n/a 16.96
Cost of blending 126,936 25,799 – – – 152,735
Change in inventory position 4 590 1,024 (145) – 1,473
Production costs 210,958 168,146 50,113 35,319 (16,318) 448,218
1  See definition on page 21 under “Non-IFRS measures”.
2  USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and for 2024.
3   Included in the Malaysia operating costs is the lease cost for the FPSO Bertam which is owned by the Group. Other represents the FPSO Bertam 
lease fee self-to-self payment elimination. Netting the self-to-self elimination against the operating costs in Malaysia reduces the operating costs 
per boe for Malaysia to USD 31.95 for Q4 2025 and USD 28.89 for the comparative period and USD 38.14 and USD 23.27 for the year ended 
December 31, 2025, and December 31, 2024, respectively.
Operating costs
Operating costs amounted to USD 77,067 thousand for Q4 2025 compared to USD 79,439 thousand for Q4 2024 and USD
292,369 thousand for 2025 compared to USD 294,010 thousand for 2024. Operating costs per boe amounted to USD 18.38 per 
boe in Q4 2025 in line with the guidance for the quarter and compared with USD 18.21 per boe in Q4 2024.
Cost of blending
For the Suffield area and Onion Lake Thermal assets in Canada, oil production is blended with purchased diluent to meet pipeline 
specifications. As a result of the blending, actual sales volumes are higher than produced barrels and the realized sales price of a 
blended barrel is higher than an unblended barrel.
The cost of the diluent amounted to USD 31,184 thousand for Q4 2025 compared to USD 36,036 thousand for Q4 2024 and USD 
134,630 thousand for 2025 compared to USD 152,735 thousand for the comparative period. 
Change in inventory position
The Bertam field in Malaysia is located offshore and production is lifted and sold from the FPSO Bertam when a cargo parcel size 
is reached. Accordingly, the timing of a lifting varies based on the inventory level on the FPSO facility and the change in inventory 
position varies, both positively and negatively, from period to period. Inventories are valued at the lower of cost including depletion, 
and market value, and the difference in the valuation between period ends is reflected in the change in inventory position in the 
statement of operations. At the end of Q4 2025, IPC had crude entitlement of 106,000 bbls of oil on the FPSO Bertam facility 
being crude produced but not yet sold. 
Depletion costs
The total depletion of oil and gas properties amounted to USD 32,167 thousand for Q4 2025 compared to USD 32,087 thousand 
for Q4 2024 and USD 122,749 thousand for the full year 2025 compared to USD 128,392 thousand for the full year 2024.
The depletion charge is analyzed in the following tables:
Three months ended – December 31, 2025
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,952 12,076 7,048 3,091 32,167
USD per boe 6.84 5.41 22.32 16.34 7.67
Three months ended – December 31, 2024
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,141 12,960 7,273 2,713 32,087
USD per boe 6.61 5.27 22.39 13.88 7.36
Year ended – December 31, 2025
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 37,994 49,455 24,194 11,106 122,749
USD per boe 6.88 5.50 22.32 14.33 7.49
18

===== SIDA 62 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Year ended – December 31, 2024
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 36,554 52,029 27,481 12,328 128,392
USD per boe 6.85 5.36 19.51 13.95 7.40
The depletion charge is derived by applying the depletion rate per boe to the volumes produced in the period by each field. 
Depreciation of other tangible fixed assets
The total depreciation of other tangible fixed assets amounted to USD 800 thousand for Q4 2025 compared to USD 2,430 
thousand for Q4 2024 and USD 5,597 thousand for the year ended December 31, 2025 compared to USD 8,933 thousand for the 
year ended December 31, 2024. This relates to the depreciation of the FPSO Bertam, which has been depreciated to its residual 
value.
Exploration and business development costs
The total exploration and business developments costs amounted to a cost of USD 1,799 thousand for the year ended December 
31, 2025 and USD 2,069 thousand for the comparative period.
Net financial items
Net financial items amounted to a charge of USD 65,765 thousand for the year ended December 31, 2025 compared to a charge 
of USD 59,709 thousand for the year ended December 31, 2024. Net financial items included a realized currency hedge loss of 
USD 9,029 thousand and a net foreign exchange gain of USD 14,654 thousand for 2025 compared to a realized currency hedge 
loss of USD 10,773 thousand and a net foreign exchange loss of USD 12,654 thousand for the year ended December 31, 2024. 
The foreign exchange movements are mainly resulting from the revaluation of intra-group loan funding balances and are non-cash 
items.
 
Excluding foreign exchange movements and realized currency cashflow hedges, the net financial items amounted to a charge of 
USD 71,390 thousand for the year ended December 31, 2025 compared to USD 36,282 thousand for the year ended December 
31, 2024. 
The interest expense amounted to USD 41,983 thousand for the year ended December 31, 2025 compared to USD 35,905 
thousand for the comparative period in 2024, mainly related to the bond interest at a fixed coupon rate of 7.25% per annum for 
the previous bonds and of 7.5% for the new bonds from October 2025. In Q4 2025, the remaining capitalized bond discount 
recognized in the balance sheet with the completion of the tap issue of USD 150 million in 2023 were charged to the interest 
expense line. Interest income generated on cash balances held amounted to USD 3,160 thousand for the year ended December 
31, 2025 and USD 17,721 thousand for the year ended December 31, 2024.
In Q4 2025, net financial items included approximately USD 16 million of costs relating to the refinancing of the USD 450 million 
senior unsecured bonds. That amount includes the call option paid (cash cost) to redeem the previous bonds as well as the 
amortisation (non-cash) of prior costs associated with the issuance of a portion of the previous bonds. The cash costs associated 
with the issuance of the new bonds are capitalised and will be amortised over the tenor of these bonds. The total cash costs from 
the new bonds issuance amounted to approximately USD 18 million. See “Financial Position and Liquidity – Financing” below.
The unwinding of the asset retirement obligation discount rate amounted to USD 16,498 thousand for the year ended December 
31, 2025 compared to USD 14,568 thousand for the year ended December 31, 2024. 
Income tax
The corporate income tax amounted to a charge of USD 17,380 thousand for the year ended December 31, 2025 compared to a 
charge of USD 33,325 thousand for the year ended December 31, 2024.
The current income tax amounted to a charge of USD 9 thousand for the year ended December 31, 2025 and a charge of USD 
8,313 thousand the year ended December 31, 2024 and mainly related to France. No corporate income tax is expected to be 
payable in Canada in 2025 due to the usage of historical tax pools. 
19

===== SIDA 63 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Capital Expenditure
Development and exploration and evaluation expenditures incurred during the year ended December 31, 2025 was as follows:
USD Thousands
Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 278,933 8,942 40,877 5,759 334,511
Exploration and evaluation 3,731 – – 15 3,746
282,664 8,942 40,877 5,774 338,257
Capital expenditures of USD 338,257 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project and in 
Malaysia for the A21 infill well drilling.
On October 24, 2025, IPC completed an acquisition of certain undeveloped petroleum and natural gas mineral rights adjacent to 
our Blackrod oilsands project in Northern Alberta for total purchase consideration of USD 7.3 million (CAD 10 million).
Other tangible fixed assets
Other tangible fixed assets amounted to USD 11,220 thousand as at December 31, 2025, which included USD 9,200 thousand in 
respect of the FPSO Bertam. The FPSO Bertam has been depreciated to its residual value.
Financial Position and Liquidity
Financing 
As at January 1, 2025, IPC had MUSD 450 of senior unsecured bonds outstanding, maturing in February 2027 with a fixed coupon 
rate of 7.25% per annum. In October 2025, IPC completed the issuance of USD 450 million of new senior unsecured bonds, 
maturing in October 2030 with a fixed coupon rate of 7.50% per annum, payable in semi-annual instalments in April and October, 
and with semi-annual amortizations of USD 25 million commencing in April 2028. The proceeds of the new bonds were used 
to fully redeem and cancel the previous bonds. IPC exercised its call option to redeem the previous bonds at a price equal to 
102.18% of the nominal amount, plus accrued and unpaid interest. The cash refinancing costs, which include the call option costs 
of the previous bonds, and the related transaction costs, incurred in Q4 2025, amounted to approximately USD 18 million.
The bond repayment obligations as at December 31, 2025, are classified as non-current as there are no mandatory repayments 
within the next twelve months.
In addition, as at December 31, 2025, the Group had a senior secured revolving credit facility of CAD 250 million (the “Canadian 
RCF”) in connection with its oil and gas assets in Canada, with a maturity date in May 2027. As at December 31, 2025, CAD 53 
million (approximately USD 39 million) was drawn under the Canadian RCF . As at December 31, 2025, the Group also had a letter 
of credit facility in Canada (the “LC Facility”) to cover operational letters of credit. As at December 31, 2025, operational letters of 
credit in an aggregate of CAD 19.7 million have been issued under the LC Facility, of which one letter of credit of CAD 5.3 million 
was fully released in January 2026.
As at December 31, 2025, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May 2026. 
IPC makes quarterly repayments of the France Facility and the amount remaining outstanding under the France Facility as at 
December 31, 2025 was USD 1.9 million (EUR 1.7 million) which is classified as current representing the repayment planned 
within the next twelve months.
The Group is in compliance with the covenants of the bonds and its financing facilities as at December 31, 2025.
Net debt as at December 31, 2025 amounted to USD 484 million. Cash and cash equivalents held amounted to USD 7 million as at 
December 31, 2025.
IPC intends to fund the budgeted capital expenditures in 2026 with forecast cash flow generated by its operations, cash on hand 
and Canadian RCF loan drawing.
Working Capital 
As at December 31, 2025, the Group had a working capital balance including cash of negative USD 29,946 thousand compared 
to USD 190,771 thousand as at December 31, 2024. The difference is mainly a result of the decreased cash following capital 
expenditures on the Blackrod Phase 1 development project and the continuing NCIB program. 
20

===== SIDA 64 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Non-IFRS Measures
In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free 
cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do
not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by 
other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in 
accordance with IFRS.
The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by and 
the financial performance and condition of the Corporation. Management also uses non-IFRS measures internally in order to 
facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s 
ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures 
are important supplemental measures of operating performance because they highlight trends in the core business that may 
not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for 
assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable
between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties frequently 
use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the purpose of 
presenting information about management’s current expectations and plans relating to the future and readers are cautioned that 
such statements may not be appropriate for other purposes.
“Operating cash flow” is calculated as revenue less production costs including net sales of diluent less current tax. Operating cash 
flow is used to analyze the amount of cash that is being generated available for capital investment and servicing debt.
“Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures 
less general and administrative expenses before depreciation and less cash financial items. Free cash flow is used to analyze 
the amount of cash that is being generated by the business and that is available for such purposes as repaying debt, funding 
acquisitions and returning capital to shareholders.
“EBITDA” is calculated as net result before financial items, taxes, depletion of oil and gas properties, exploration and business 
development costs, impairment costs and depreciation and before non-recurring profit/loss on sale of assets and other income.
“Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is 
used to analyze the cash cost of producing the oil and gas volumes.
“Net debt” is calculated as bank loans and bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash 
equivalents less bank loans and bonds. 
Reconciliation of Non-IFRS Measures
Operating cash flow
The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended 
December 31
Year ended
December 31
2025 2024 2025 2024
Revenue 176,207 199,124 685,888 797,783 
Production costs and net sales of diluent to third party1 (113,814) (119,371) (426,976) (447,481)
Current tax 745 (1,595) (9) (8,313)
Operating cash flow 63,138 78,158 258,903 341,989 
1 Includes net sales of diluent to third party amounting to USD 137 thousand for the fourth quarter of 2025 and USD 647 thousand for the year 
ended December 31, 2025.
21

===== SIDA 65 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Free cash flow
The following table sets out how free cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended 
December 31
Year ended
December 31
2025 2024 2025 2024
Operating cash flow - see above 63,138 78,158 258,903 341,989 
Capital expenditures (61,318) (126,256) (338,257) (434,713)
Abandonment and farm-in expenditures1 (1,810) (3,364) 1,146 (8,302)
General, administration and depreciation expenses before 
depreciation2 (3,427) (3,569) (15,375) (14,814)
Cash financial items3 (25,210) (6,445) (59,551) (19,657)
Free cash flow (28,627) (61,476) (153,134) (135,497)
1  See 19 to the Financial Statements. Includes in 2025 secured amounts received of USD 7.7 million towards the future asset retirement obligation 
for the Bertam field.
2  Depreciation is not specifically disclosed in the Financial Statements.
3  See notes 5 and 6 to the Financial Statements.
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended 
December 31
Year ended
December 31
2025 2024 2025 2024
Net result (4,941) 415 28,942 102,219 
Net financial items 26,039 35,767 65,765 59,709 
Income tax 3,504 3,852 17,380 33,325 
Depletion and decommissioning costs 32,167 32,087 122,749 128,392 
Depreciation of other tangible fixed assets 800 2,430 5,597 8,933 
Exploration and business development costs 1,047 1,725 1,799 2,069
Sale of assets1 –  (400) (104) (400)
Depreciation included in general and administrative expenses2 350 308 1,409 1,241
EBITDA 58,966 76,184 243,537 335,488
1 Sale of assets is included under “Other income/(expense)“but not specifically disclosed in the Financial Statements
2 Item is not shown in the Financial Statements.
Operating costs
The following table sets out how operating costs is calculated: 
USD Thousands
Three months ended 
December 31
Year ended
December 31
2025 2024 2025 2024
Production costs 113,951 120,108 427,623 448,218 
Cost of blending (31,184) (36,036) (134,630) (152,735)
Change in inventory position (5,700) (4,633) (624) (1,473)
Operating costs 77,067 79,439 292,369 294,010 
22

===== SIDA 66 =====

Management’s Discussion and Analysis
For the three months and year ended December 31, 2025
Net cash/(debt)
The following table sets out how net cash/(debt) is calculated: 
USD Thousands December 31, 2025 December 31, 2024
Bank loans (40,652) (5,121)
Bonds (450,000) (450,000)
Cash and cash equivalents 7,037 246,593 
Net cash/(debt) (483,615) (208,528)
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, had issued seven letters of credit as at December 31, 2025 as follows: (a) MCAD 2.6 
in respect of its obligations to purchase diluent; (b) MCAD 1.0 in respect of its obligations related to the Ferguson asset; (c) MCAD 
1.3 in respect of pipeline access; (d) MCAD 0.5 in respect of the hedging of electricity prices; (e) MCAD 3.9 in respect of electricity 
distribution services; and (f) two letters of credit of MCAD 5.3 each in respect of the land acquisition completed in October 2025, 
of which one letter of credit of MCAD 5.3 was fully released in January 2026.
Outstanding Share Data 
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2024, IPC had a total of 126,992,066 common shares issued and outstanding, with no common shares held in 
treasury. From January 1, 2024 to December 4, 2024, IPC purchased and cancelled a total of 7,109,365 common shares under the 
normal course issuer bid/share repurchase program (NCIB). The NCIB was further renewed in Q4 2024, with IPC being entitled to 
purchase up to 7,465,356 common shares over the period of December 5, 2024 to December 4, 2025. During December 2024, 
IPC purchased 823,386 and cancelled 713,230 common shares under the renewed NCIB, for an aggregate of 7,822,595 common 
shares cancelled in 2024.
As at December 31, 2024, IPC had a total of 119,169,471 common shares issued and outstanding and held 110,156 common 
shares held in treasury.
Over the period of January 1, 2025 to December 4, 2025, IPC purchased and cancelled 6,641,970 common shares under the NCIB 
and 261,818 common shares under certain other exemptions in Canada.
As at December 31, 2025 and February 10, 2026, IPC had a total of 112,155,527 common shares issued and outstanding, with no 
common shares held in treasury.
Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 42,597,533 
common shares in IPC, representing 38.0% of the outstanding common shares as at December 31, 2025.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares.
IPC has 2,577,198 IPC Share Unit Plan awards outstanding as at February 10, 2026 of which 789,431 awards were granted in 
2026.
The Corporation is authorized to issue an unlimited number of common shares without par value. The Corporation is also 
authorized to issue an unlimited number of class A preferred shares and an unlimited number of class B preferred shares, issuable 
in series.
Contractual Obligations and Commitments 
In the normal course of business, the Group has committed to certain payments which are not recognized as liabilities. The 
following table summarizes the Group’s commitments in Canada as at December 31, 2025: 
MCAD 2026 2027 2028 2029 2030 Thereafter
Transportation service1  60.4     91.6     99.1     103.1     103.9     1,384.7    
Power2  12.4     12.4     9.8     –      –       –     
Total commitments  72.8     104.0     108.9     103.1     103.9     1,384.7    
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2046.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from January 1, 2026 to December
31, 2028, and an additional 5MWh at a weighted average price of CAD 58.31/MWh from January 1, 2026 to December 31, 2027.
23

===== SIDA 67 =====