Årsredovisning 2024

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Q4
International Petroleum Corporation
Audited Consolidated Financial 
Statements
For the years ended December 31, 2024 and 2023

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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, 2024 and 2023, AUDITED

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Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, 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 11, 2025

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4
PricewaterhouseCoopers LLP 
Suncor Energy Centre, 111 5th Avenue South West, Suite 3100, 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, 2024 and its financial performance and its cash flows for the year 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 year ended December 31, 2024; 
the consolidated statement of comprehensive income/(loss) for the year then ended; 
the consolidated balance sheet as at December 31, 2024; 
the consolidated statement of cash flow for the year then ended; 
the consolidated statement of changes in equity for the year then ended; and 
the notes to the consolidated financial statements, which include material accounting policies and 
other explanatory information. 
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.

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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, 2024. 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 Canada and 
Malaysia segments 
Refer to note 1 – Corporate information and 
material accounting policies, note 2 – Critical 
accounting estimates and judgments, and note 9 
– Property, plant and equipment to the 
consolidated financial statements. 
The Canada and Malaysia segments had 
$1,316.6 million and $69.4 million of oil and gas 
properties within PP&E, as at December 31, 
2024, and depletion charges were $88.6 million 
and $27.5 million, respectively, 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. 
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 
certain properties in the Canada and Malaysia 
segments, which included the following: 
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.

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6
Recalculated depletion charges for the Canada 
and Malaysia segments. 
Comparative information 
The consolidated financial statements of the Corporation for the year ended December 31, 2023 were 
audited by another auditor who expressed an unmodified opinion on those consolidated financial 
statements on February 6, 2024. 
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. 
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.

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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 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 
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.

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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 11, 2025

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Consolidated Statement of Operations
For the years ended December 31, 2024 and 2023, AUDITED
USD Thousands Note 2024 2023
Revenue 3 797,783 853,906
Cost of sales
Production costs 4 (448,218) (491,303)
Depletion and decommissioning costs 3,9 (128,392) (101,922)
Depreciation of other tangible fixed assets 3,9 (8,933) (7,812)
Exploration and business development costs 3 (2,069) (2,355)
Gross profit 3 210,171 250,514
Other income / (expense) 9 1,137 19,018
General, administration and depreciation expenses (16,055) (18,455)
Profit before financial items 195,253 251,077
Finance income 5 17,721 21,774
Finance costs 6 (77,430) (44,510)
Net financial items (59,709) (22,736)
Profit before tax 135,544 228,341
Income tax expense 7 (33,325) (55,362)
Net result 102,219 172,979
Net result attributable to:
Shareholders of the Parent Company 102,202 172,951 
Non-controlling interest 17 28
102,219 172,979
Earnings per share – USD1 16 0.82 1.31
Earnings per share fully diluted – USD1 16 0.81 1.28
1  Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the consolidated financial statements

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10
Consolidated Statement of Comprehensive Income/(Loss)
For the years ended December 31, 2024 and 2023, AUDITED
USD Thousands Note 2024 2023
Net result 102,219 172,979
Other comprehensive income/(loss)
Items that may be reclassified to profit or loss:
Gain/(loss) on cash flow hedges (35,498) 48,786
Reclassification of hedging (gains)/losses to profit or 
loss 3, 22 (22,370) (18,928)
Income tax relating to these items 13,753 (7,051)
Currency translation adjustments (73,931) 20,994
Items that will not be reclassified to profit or loss:
Re-measurements on defined pension plan 20 (3,491) (679)
Total comprehensive income/(loss) (19,318) 216,101
Total comprehensive income/(loss) attributable to:
Shareholders of the Parent Company (19,329) 216,076
Non-controlling interest 11 25
(19,318) 216,101
See accompanying notes to the consolidated financial statements

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11
Consolidated Balance Sheet
As at December 31, 2024 and 2023, AUDITED
USD Thousands Note December 31, 2024 December 31, 2023
ASSETS
Non-current assets
Exploration and evaluation assets 8 480 –
Property, Plant and Equipment 9 1,500,912 1,303,860
Right-of-use assets 10 3,103 2,814
Deferred tax assets 7 1,673 1,827
Derivative instruments 22, 23 – 7,049
Other non-current assets 11 48,665 56,838
Total non-current assets 1,554,833 1,372,388
Current assets
Inventories 12 20,073 21,808
Trade and other receivables 13 127,450 113,497
Derivative instruments 22, 23 3,219 35,504
Current tax receivables 1,514 2,714
Cash and cash equivalents 14 246,593 517,074
Total current assets 398,849 690,597
TOTAL ASSETS 1,953,682 2,062,985
LIABILITIES
Non-current liabilities
Financial liabilities 18, 22 1,719 5,442
Bonds 18, 22 439,862 435,041
Lease liabilities 10 2,728 2,087
Provisions 19 268,509 250,657
Deferred tax liabilities 7 92,754 86,348
Derivative instruments 22,23 562 263
Total non-current liabilities 806,134 779,838
Current liabilities
Trade and other payables 21 176,371 188,871
Financial liabilities 18,22 3,402 3,589
Derivative instruments 22, 23 19,869 1,267
Current tax liabilities 1,146 255
Lease liabilities 10 573 809
Provisions 19 6,717 8,097
Total current liabilities 208,078 202,888
EQUITY
Shareholders’ equity 939,315 1,080,074
Non-controlling interest 155 185
Net shareholders’ equity 939,470 1,080,259
TOTAL EQUITY AND LIABILITIES 1,953,682 2,062,985
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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Consolidated Statement of Cash Flow
For the years ended December 31, 2024 and 2023, AUDITED
USD Thousands Note 2024 2023
Cash flow from operating activities
Net result 102,219 172,979
Depletion, depreciation and amortization 3, 9,10 138,566 111,303
Write-off of exploration costs 8 1,419 – 
Gain on sale of assets 9 (400) (19,018)
Income tax 7 33,325 55,362
Amortization of capitalized financing fees 6 2,057 1,605
Foreign currency exchange loss/(gain) 6 23,427 1,911 
Interest income 5 (17,721) (21,774)
Interest expense 6 35,905 25,635 
Unwinding of asset retirement obligation discount 6 14,568 13,408 
Change in pension liability 20 682 446
Share-based costs 17 8,539 11,690
Changes in working capital  (47,092) 36,058
Decommissioning costs paid 19 (7,711) (8,118)
Other payments 19 (1,997) (2,370)
Net income taxes paid (6,362) (34,868)
Interest received 18,619 20,884
Interest paid (32,821) (21,977)
Other 865 2,998
Net cash flow from operating activities 266,087 346,154
Cash flow used in investing activities
Investment in oil and gas properties 9 (432,794) (312,690)
Investment in exploration and evaluation assets 8 (1,919) (39)
Disposal of assets 9 221 20,191
Acquisitions net of cash acquired 9 – (59,419)
Investment in other tangible fixed assets (363) (510)
Net cash (outflow) from investing activities (434,855) (352,467)
Cash flow from financing activities
Repayments 18 (3,910) (3,111) 
Net bonds issuance proceeds 18 – 137,550
Paid financing fees – (507)
Repurchase of own shares (“NCIB”) 15 (102,188) (95,358)
Other payments (964) (980)
Dividend paid (41) (31)
Net cash (outflow) from financing activities (107,103) 37,563
Change in cash and cash equivalents (275,871) 31,250
Cash and cash equivalents at the beginning of the 
year 517,074 487,240
Currency exchange difference in cash and cash 
equivalents 5,390 (1,416)
Cash and cash equivalents at the end of the year 246,593 517,074
   
See accompanying notes to the consolidated financial statements

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Consolidated Statement of Changes in Equity
For the years ended December 31, 2024 and 2023, 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, 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 shares 
(NCIB)1 (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. 
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, 2023 338,719 635,895 (31,292) 11,349 7,958 2,511 965,140 191 965,331
Net result – 172,951 – – – – 172,951 28 172,979
Re-measurements on defined
pension plan – – – – – (679) (679) – (679) 
Acquisitions of Cor41 – – – – 881 – 881 – 881
Cash flow hedges – – – – 21,926 – 21,926 – 21,926
Currency translation difference – – 20,547 (83) 579 (46) 20,997 (3) 20,994
Total comprehensive income – 172,951 20,547 (83) 23,386 (725) 216,076 25 216,101
Dividend distribution – – – – – – – (31) (31)
Repurchase of own shares 
(NCIB)2 (95,358) – – – – – (95,358) – (95,358) 
Share based costs – – – 13,535 – – 13,535 – 13,535 
Share based payments3                     – (13,356) – (5,963) – – (19,319) – (19,319)
Balance at December 31, 2023 243,361 795,490 (10,745) 18,838 31,344 1,786 1,080,074 185 1,080,259
1  See Note 9
2 See Note 15
3 The third instalment of IPC RSP 2020 awards, the second instalment of IPC RSP 2021 awards, the first instalment of IPC RSP 2022 awards and 
the IPC PSP 2020 awards vested on February 1, 2023, at a price of CAD 14.26 per award. The difference between the value at vesting date 
and at grant (respectively CAD 4.35 per award, CAD 4.07 per award, CAD 9.09 per award and CAD 3.65 per award) was offset against retained 
earnings. 
See accompanying notes to the consolidated financial statements

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Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, 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 (“TSX”) 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.
On March 3, 2023, IPC completed the acquisition (the “Cor4 acquisition”) of all of the issued and outstanding shares of Cor4 Oil 
Corp. (“Cor4”). On June 1, 2023, Cor4 was amalgamated into IPC Canada Ltd.
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 11, 2025.
C. Change in presentation
Certain comparative figures have been reclassified to conform with the financial statements presentation in the current year, more 
specifically the following item:
• Oil and gas properties and other tangible fixed assets, formerly presented separately as “Oil and gas properties” and “Other 
tangible fixed assets”, are now presented together on the consolidated balance sheet as “Property, Plant and Equipment”. 
Refer to Note 9.
D. Going concern
The Group’s consolidated financial statements for the year ended December 31, 2024, 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, 2024, the Group applied the amended accounting standards, interpretations and annual
improvement points that are effective as of January 1, 2024. 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 
On April 9, 2024, the International Accounting Standards Boards issued IFRS 18 Presentation and Disclosure in Financial 
Statements (”IFRS 18”), which aims to improve how companies communicate their financial statements, with a focus on 
information about financial performance in the statement of profit or loss. IFRS 18 is effective January 1, 2027. The Company is in 
the process of assessing the impact that the standard will have on its financial statements.
On May 30, 2024, the International Accounting Standards Board issued amendments to IFRS 9 Financial Instruments and IFRS 7 
Financial Instruments: Disclosures, which aim to improve the classification and measurement of financial instruments, including 
clarifications on contractual cash flow characteristics and Environmental, Social and Governance-related features (”ESG”). The 
amendments are effective for annual reporting periods beginning on or after January 1, 2026, with early application permitted. The 
Company is in the process of assessing the impact that these amendments will have on its financial statements.

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Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, 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, 2024 December 31, 2023
Average Year end Average Year end
1 EUR equals USD 1.0821 1.0389 1.0816 1.1050
1 USD equals CAD 1.3698 1.4388 1.3496 1.3251
1 USD equals MYR 4.5759 4.4715 4.5598 4.5950
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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Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, 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 dicounted 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, is being depreciated to its residual 
value on a unit of production basis to August 2025.
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.

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Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, 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, 2024 and 2023, AUDITED

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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, 2024 and 2023, AUDITED

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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:
Estimates of oil and gas reserves
Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and asset 
retirement obligation. Standard recognized evaluation techniques are used to estimate the proved and probable reserves. These 
techniques take into account the future level of development required to produce the reserves. Independent qualified reserves 
auditors reviews these estimates. Changes in estimates in oil and gas reserves, resulting in different future production profiles, 
will affect the discounted cash flows used in impairment testing, the anticipated date of site decommissioning and restoration 
and the depletion charges in accordance with the unit of production method. Changes in estimates in oil and gas reserves could 
for example result from additional drilling, observation of long-term reservoir performance or changes in economic factors such 
as oil price and inflation rates. Significant assumptions developed by management used to determine estimates of proved and 
probable oil and gas reserves include expected production volumes, future oil and gas prices, future development costs and future 
production costs.
Impairment of oil and gas properties 
Impairment tests are performed when there are indicators of impairment. Key assumptions in the impairment models relate to 
prices and costs that are based on forward curves and the long-term corporate assumptions. The impairment test requires the 
use of estimates. For the purpose of determining a potential impairment, the significant assumptions developed by management 
used to determine the recoverable amount include the estimates of oil an gas reserves and the discount rate. These assumptions 
and judgements of management that are based on them are subject to change as new information becomes available. Changes in 
economic conditions can also affect the rate used to discount future cash flow estimates and the discount rate applied is reviewed 
throughout the year.
Provision for asset retirement obligations 
Amounts used in recording a provision for asset retirement obligations are estimates based on current legal and constructive 
requirements and current technology and price levels for the removal of facilities and decommissioning. Due to changes in relation 
to these items, the future actual cash outflows in relation to the site decommissioning and restoration can be different. To reflect 
the effects due to changes in legislation, requirements and technology and price levels, the carrying amounts of asset retirement 
obligation 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.
Fair value of assets acquired and liabilities assumed in a business combination
The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and 
any goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied 
for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward 
commodity prices, reserves and resources estimates, production costs and discount rates. Changes in these variables could 
significantly impact the carrying value of the net assets.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, 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.
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  156,630 33,829 19,959 (247) 210,171
2023
USD Thousands Canada Malaysia France Other Total
Crude oil 688,891 101,237 81,093 – 871,221
NGLs 1,172 – – – 1,172
Gas 67,338 – – – 67,338
Net sales of oil and gas 757,401 101,237 81,093 – 939,731
Change in under/over lift position – – 400 – 400
Royalties (101,177) – (5,120) – (106,297)
Hedging settlement 18,928 – – – 18,928
Other operating revenue 7 – 867 270 1,144
Revenue 675,159 101,237 77,240 270 853,906
Operating costs (249,995) (35,679) (36,288) – (321,962)
Cost of blending (172,996) – – – (172,996)
Change in inventory position 504 3,358 (207) – 3,655
Depletion and decommissioning costs (70,104) (17,800) (14,018) – (101,922)
Depreciation of other tangible fixed assets – (7,812) – – (7,812)
Exploration and business development costs (834) – (39) (1,482) (2,355)
Gross profit/(loss)  181,734 43,304 26,688 (1,212) 250,514
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED

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USD Thousands
Assets Liabilities
2024 2023 2024 2023
Canada 2,010,107 1,966,370 1,226,081 1,082,035
Malaysia 165,701 175,159 104,290 112,467
France 158,518 204,006 83,581 95,840
Other 205,293 199,177 186,197 174,111
Intercompany balance elimination (585,937) (481,727) (585,937) (481,727)
Total Assets / Liabilities 1,953,682 2,062,985 1,014,212 982,726
Shareholders’ equity – – 939,315 1,080,074
Non-controlling interest – – 155 185
Total equity for the group – – 939,470 1,080,259
Total consolidated 1,953,682 2,062,985 1,953,682 2,062,985
4. PRODUCTION COSTS
USD Thousands 2024 2023
Cost of operations 251,070 275,868
Tariff and transportation expenses 38,195 40,929
Direct production taxes 4,745 5,165
Operating costs 294,010 321,962
Cost of blending1 152,735 172,996
Change in inventory position 1,473 (3,655)
Total production costs 448,218 491,303
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 2024 2023
Interest income 17,721 21,774
Total finance income 17,721 21,774
6. FINANCE COSTS
USD Thousands 2024 2023
Foreign exchange loss, net1 23,427 1,911
Interest expense 35,905 25,635
Unwinding of asset retirement obligation discount 14,568 13,408
Amortization of capitalized financing fees 2,057 1,605
Loan commitment fees 837 672
Other financial costs 636 1,279
Total finance costs 77,430 44,510
1 Includes an amount of USD 10.8 million related to realized losses on currency cashflow hedges. 
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED

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7. INCOME TAX
USD Thousands 2024 2023
Current tax (8,313) (14,457)
Deferred tax (25,012) (40,905)
Total tax expense (33,325) (55,362) 
The Group is within the scope of the OECD Pillar Two model rules. The Group applies the exception to recognising and disclosing 
information about deferred tax assets and liabilities related to Pillar Two income taxes, as provided in the amendments to IAS 12 
issued in May 2023. 
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 2024 2023
Profit before tax 135,544 228,341
Tax calculated at the corporate tax rate in Canada 25%  (33,886) (57,086)
Effect of foreign and domestic tax rates 6,473 7,470
Tax effect of recognition / (derecognition) of unrecorded tax losses  (6,216) (4,736)
Tax effect due to true-up of provision to prior year tax filings 790 (102)
Other (486) (908)
Total tax (33,325) (55,362)
Specification of deferred tax assets and tax liabilities1
USD Thousands 2024 2023
Unused tax loss carry forward  40,042 34,446
Derivative hedges  3,933 –
Other  10,302 5,959
Deferred tax assets 54,277 40,405
Accelerated allowances  145,358 115,399
Derivative hedges – 9,527
Deferred tax liabilities 145,358 124,926
Deferred taxes, net  (91,081) (84,521)
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.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED

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8. EXPLORATION AND EVALUATION ASSETS
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 – – – –
Additions 500 1,407 12 1,919
Write-off – (1,407) (12) (1,419)
Reclassification – – – –
Currency translation adjustments (20) – – (20)
Net book value December 31, 2024 480 – – 480
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 – – 4,764 4,764
Additions – – 39 39
Write-off – – (39) (39)
Reclassification – – (4,937) (4,937)
Currency translation adjustments – – 173 173
Net book value December 31, 2023 – – – –
9. PROPERTY, PLANT AND EQUIPMENT
USD Thousands 2024 2023
Oil and gas properties                1,484,487 1,278,422
Other tangible fixed assets 16,425 25,438
Property, Plant and Equipment  1,500,912 1,303,860
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED

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Oil and gas properties
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
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 1,089,789 566,606 399,237 2,055,632
Acquisition of Cor4 72,242 – – 72,242
Additions 278,613 17,873 16,204 312,690
Disposals1 (7,854) – – (7,854)
Change in estimates 24,454 6,644 1,738 32,836
Reclassification (22,857) – 4,937 (17,920)
Currency translation adjustments 30,623 – 14,577 45,200
December 31, 2023 1,465,010 591,123 436,693 2,492,826
Accumulated depletion
January 1, 2023 (323,273) (485,034) (288,714) (1,097,021)
Depletion charge for the year (94,192) (17,800) (14,018) (126,010)
Disposals1 4,474 – – 4,474
Other2 22,857 – – 22,857
Currency translation adjustments (8,154) – (10,550) (18,704)
December 31, 2023 (398,288) (502,834) (313,282) (1,214,404)
Net book value December 31, 2023 1,066,722 88,289 123,411 1,278,422
1  In Canada, includes the disposal of non-core properties in the John Lake area.
2 In Canada, includes an adjustment in the first quarter of 2023 for accelerated decommissioning activities funded by a non-cash site rehabilitation
program.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED

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

26
Cor4 acquistion
On March 3, 2023, IPC completed the acquisition of all of the issued and outstanding shares of Cor4. At such date, Cor4 became 
an indirect, wholly-owned subsidiary of IPC. Cor4 owned assets in the Brooks area, Alberta. On June 1, 2023, Cor4 was amalga-
mated into IPC Canada Ltd.
The Cor4 acquisition has been accounted for as a business combination with IPC being the acquirer, and in accordance with IFRS 3 
Business Combinations, the assets acquired and liabilities assumed have been recorded at their fair values.
The total cash consideration paid, after preliminary closing adjustments, amounted to USD 62.2 million (CAD 84.7 million).
The amounts recognized in respect of the identifiable assets acquired and liabilities assumed are as set out in the table below:
USD Thousands
Cash 2,792
Trade and other receivables 7,671
Prepaid expenses and deposits 2,417
Fair value of risk management assets 1,144
Deferred tax assets 19,334
Right-of-use assets 109
Property, plant and equipment 72,242
Accounts payable and accrued liabilities (12,623)
Right-of-use liabilities (109)
Decommissioning liabilities (29,885)
Mark-To-Market (“MTM”) reserve in equity (881)
Total Consideration 62,211
Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during the year 
ended December 31, 2023.
Decommissioning liabilities
The fair value of the decommissioning liability at the acquisition date was based on the estimated future cash flows to 
decommission the acquired oil and natural gas properties at the end of their useful life. The discount rate used to determine the 
net present value of the decommissioning obligation was a credit risk adjusted rate of 8%.
Impairment test
As of December 31, 2024, 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.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED

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

27
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
Other tangible fixed assets
USD Thousands FPSO Other 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
USD Thousands FPSO Other Total
Cost
January 1, 2023 204,853 9,779 214,632
Additions – 510 510
Disposals – (487) (487)
Currency translation adjustments – 246 246
December 31, 2023 204,853 10,048 214,901
Accumulated depreciation
January 1, 2023 (173,311) (7,947) (181,258)
Depreciation charge for the year (7,812) (684) (8,496)
Disposals – 487 487
Currency translation adjustments – (196) (196)
December 31, 2023 (181,123) (8,340) (189,463)
Net book value December 31, 2023 23,730 1,708 25,438
1  Depreciation of Other is included in General, administration and depreciation expenses in the statement of operations.
The Floating Production Storage and Offloading facility (“FPSO“) located on the Bertam field, Malaysia, is being depreciated to its 
residual value on a unit of production basis to August 2025. 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, administration and depreciation expenses in the Statement of 
Operations.

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

28
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
10. RIGHT-OF-USE ASSETS AND LEASE LIABILITIES
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
USD Thousands Total
January 1, 2023 1,217
Acquisition of Cor4 - See note 9 109
Additions 2,508
Disposal (162)
Depreciation (885)
Currency translation adjustments 27
Right-of-use-assets as at December 31, 2023 2,814
Current 809
Non-Current 2,087
Lease Liabilities as at December 31, 2023 2,896
11. OTHER NON-CURRENT ASSETS
USD Thousands December 31, 2024 December 31, 2023
Financial assets  34,788   41,486
Intangible assets  13,877    15,352
 48,665       56,838
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 30.6 million (2023: USD 28.7 million). Financial assets also include cash-
collateralized guarantees placed in 2023 in respect of work commitments in Malaysia amounting to USD 4.0 million. 
Intangible assets mainly represent carbon offsets purchased in Canada. 
12. INVENTORIES
USD Thousands December 31, 2024 December 31, 2023
Hydrocarbon stocks  11,250    13,530    
Well supplies and operational spares  8,823    8,278
 20,073    21,808

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

29
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
13. TRADE AND OTHER RECEIVABLES
USD Thousands December 31, 2024 December 31, 2023
Trade receivables 94,265     97,264
Underlift 1,007       1,029
Joint operations debtors 1,432    910
Prepaid expenses and accrued income 12,346 10,986
Other 18,400 3,308
127,450    113,497
Other receivables include secured amounts of USD 7.7 million towards the future asset retirement obligation for the Bertam 
field.
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, 2023 136,827,999
Cancellation of repurchased common shares (NCIB) (9,835,933)
Balance at December 31, 2023 126,992,066
Cancellation of repurchased common shares (NCIB) (7,822,595)
Balance at December 31, 2024 119,169,471
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, 2023, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in 
treasury.
During 2023, under the normal course issuer bid (NCIB) announced in December 2022 and renewed in December 2023, IPC 
purchased and cancelled an aggregate of 9,835,933 common shares.
As at December 31, 2023, 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 NCIB.
The NCIB was further renewed in Q4 2024 and IPC is 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 on 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.
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.

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

30
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
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.
2024 2023
Net result attributable to shareholders of the Parent Company, USD 102,201,942 172,951,130
Weighted average number of shares for the year 124,072,452 132,080,662
Earnings per share, USD  0.82 1.31
Weighted average diluted number of shares for the year  126,299,688 135,349,211
Earnings per share fully diluted, USD 0.81 1.28
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”) 2021 awards vested on February 1, 2024 at a price of CAD 14.90 per award.
The IPC PSP 2022 awards are subject to continued employment and to certain performance conditions being met. The total 
outstanding number of awards at December 31, 2024, is 937,000 which vested on February 1, 2025 at a price of CAD 18.89. Each 
award was fair valued at the grant date at CAD 8.40 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 0.38%, 
expected volatility of 45%, dividend yield rate of 0%, and an exercise price of CAD zero.
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, 2024, is 813,000 which vest on February 1, 2026. 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, 2024, 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.
IPC Performance Share Plan 2021 Awards 2022 Awards 2023 Awards 2024 Awards Total
Outstanding at January 1, 2024 1,716,000 937,000 813,000 – 3,466,000
Awarded during the year – – – 819,000 819,000
Forfeited during the year – – – – –
Vested during the year (1,716,000) – – – (1,716,000)
Outstanding at December 31, 2024 – 937,000 813,000 819,000 2,569,000
Vesting date
February 1, 2025 – 937,000 – – 937,000
February 1, 2026 – – 813,000 – 813,000
February 1, 2027 – – – 819,000 819,000
Outstanding at December 31, 2024 – 937,000 813,000 819,000 2,569,000
The third instalment of the IPC Restricted Share Plan (“RSP”) 2021 awards vested on February 1, 2024, at a price of CAD 14.90 
per award.

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

31
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
The second instalment of the IPC RSP 2022 awards vested on February 1, 2024, at a price of CAD 14.90 per award. The total 
outstanding number of 2022 awards under the IPC RSP as at December 31, 2024, is 151,035 which vested on February 1, 2025, at 
a price of CAD 18.89. Each award was fair valued at the grant date at CAD 9.09.
The first instalment of the IPC RSP 2023 awards vested on February 1, 2024, at a price of CAD 14.90 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 third instalment vest 
on February 1, 2026, subject to continued employment. 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 and 
third instalment vest respectively on February 1, 2026, and February 1, 2027, subject to continued employment. Each award was 
fair valued at the grant date at CAD 14.82.
IPC Restricted Share Plan 2021 Awards 2022 Awards 2023 Awards 2024 Awards Total
Outstanding at January 1, 2024 321,512 307,359 330,708 – 959,579
Awarded during the year – – – 370,338 370,338
Forfeited during the year – (2,082) (3,436) (6,303) (11,821)
Vested during the year (321,512) (154,242) (110,192) – (585,946)
Outstanding at December 31, 2024 – 151,035 217,080 364,035 732,150
Vesting date
February 1, 2025 – 151,035 108,916 122,095 382,046
February 1, 2026 – – 108,164 121,131 229,295
February 1, 2027 – – – 120,809 120,809
Outstanding at December 31, 2024 – 151,035 217,080 364,035 732,150
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, 2024 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, 2024 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, 2024 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, 2024 is 4,328 awards issued with a fair value at the grant date at CAD 18.19 
and 5,607 awards issued with a fair value at the grant date at CAD 15.72. The total outstanding RSP awards outstanding as at 
December 31, 2024, is 24,418.
The costs charged to the statement of operations of the Group for the Share-Based payments are summarized in the following 
table:
USD Thousands 2024 2023
IPC PSP – 2020 Awards – 159
IPC RSP – 2020 Awards – 35
IPC PSP – 2021 Awards 108 1,881
IPC RSP – 2021 Awards 52 377
IPC PSP – 2022 Awards 1,477 2,856
IPC RSP – 2022 Awards 464 1,063
IPC PSP – 2023 Awards 1,728 3,360
IPC RSP – 2023 Awards 1,048 1,959
IPC PSP – 2024 Awards 1,414 –
IPC RSP – 2024 Awards 2,248 –
8,539 11,690

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

32
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
18. FINANCIAL LIABILITIES
USD Thousands December 31, 2024 December 31, 2023
Current bank loans 3,402 3,589
Non current bank loans 1,719 5,442
Bonds 443,407 440,288
Capitalized financing fees (3,545) (5,247)
444,983 444,072
As at January 2023, IPC had USD 300 million of bonds outstanding, issued in February 2022 and maturing in February 2027 with a
fixed coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group also had a revolving
credit facility of CAD 75 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada. 
In Q3 2023, IPC completed a tap issue of USD 150 million under IPC’s existing 7.25% bond framework issued at 7% discount
to par value with proceeds amounting to USD 139.5 million before transaction costs. For accounting purposes, the discounted
amount was recognised in the balance sheet and the discount will be unwound over the period to maturity of the bond and
charged to the interest expense line of the statement of operations using the effective interest rate methodology. As at
December 31, 2024, IPC had a nominal USD 450 million of bonds outstanding with maturity in February 2027. The bond repayment 
obligations as at December 31, 2024, are classified as non-current as there are no mandatory repayments within the next twelve 
months.
During 2023, the Group increased the Canadian RCF from MCAD 75 to MCAD 180 with a maturity to May 2025. During Q2 
2024, the Group extended the maturity of the Canadian RCF to May 2026. The Canadian RCF is undrawn and fully available as at 
December 31, 2024. During Q3 2024, the Group entered into a letter of credit facility in Canada (the “LC Facility”) to cover existing 
operational letters of credit. As at December 31, 2024, operational letters of credit in an aggregate of MCAD 40.2 have been 
issued under the LC Facility, including letters of credit issued in Q2 2024 for a total amount of MCAD 35 to support the third party 
pipeline construction agreements for the Blackrod project during 2024 and 2025.
As at December 31, 2024, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May
2026. IPC makes quarterly repayments of the French Facility and the amount remaining outstanding under the France Facility as at 
December 31, 2024 was USD 5.1 million (EUR 4.9 million). An amount of USD 3.4 million (EUR 3.3 million) drawn under the France 
Facility as at December 31, 2024 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, 2024. 
The net (debt)/cash reconciliation can be summarized as follows:
USD Thousands December 31, 2024 December 31, 2023
Cash and cash equivalents 246,593    517,074 
Bonds  (443,407) (440,288)
Borrowings (5,121)    (9,031)
Lease liabilities (3,301) (2,896)
Net (debt)/cash (205,236)  64,859

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

33
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
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, 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)
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, 2023 487,240 (1,259) (3,431) (8,711) (300,000) 173,839
Cash flows 31,250 980 – 3,111 (140,288) (104,947)
Reclassification Long term / Short term – – (158) 158 – –
Additional leases – (2,651) – – – (2,651)
Currency translation adjustments (1,416) 34 – – – (1,382)
Net (debt)/cash as at December 31, 2023 517,074 (2,896) (3,589) (5,442) (440,288) 64,859
Net cash (excluding lease liabilities and 
including the redeemable bonds value 
at maturity (USD 450 million)) 
58,043
19. PROVISIONS
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).

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

34
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2023 206,249 3,404 306 1,478 211,437
Acquisition of Cor4 - See note 9 29,885 – – – 29,885
Additions – – 446 938 1,384
Unwinding of asset retirement obligation discount 13,408 – – – 13,408
Disposals1 (2,483) – – – (2,483)
Changes in estimates 9,973 – 679 – 10,652
Payments (8,118) (1,081) (925) (364) (10,488)
Other2 (1,272) – – – (1,272)
Reclassification3 1,781 – – – 1,781
Currency translation adjustments 4,526 (147) 45 26 4,450
December 31, 2023 253,949 2,176 551 2,078 258,754
Non-current 246,396 1,632 551 2,078 250,657
Current 7,553 544 – – 8,097
Total 253,949 2,176 551 2,078 258,754
1 In Canada, includes the disposal of non-core properties in the John Lake area.
2 Includes accelerated decommissioning activities funded by a non cash site rehabilitation program.
3 The reclassification of the asset retirement obligation related to the 2023 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 rate of 6% (2023: 6%) per annum was used, 
based on a credit risk adjusted rate.
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, 2024 December 31, 2023
Present value of defined benefit obligation 19,569 22,241
Fair value of plan assets (15,884) (21,690)
Pension obligation, ending balance 3,685 551
The movement in the defined benefit obligation over the year is as follows:
USD Thousands For the year ended
December 31, 2024
For the year ended
December 31, 2023
Opening balance 22,241 13,910
Current service cost 608 423
Ordinary contributions paid by employees 604 617
Additional contributions paid by employees 1,340 6,685
Interest expense on defined benefit obligation 402 322
Actuarial (gain)/loss on defined benefit obligation 3,390 524
Administration costs 18 16
Benefits paid from plan assets (7,440) (2,135)
Past service cost 46 –
Foreign exchange (gain)/loss (1,640) 1,879
Defined benefit obligation, ending balance 19,569 22,241

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35
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
The weighted average duration of the defined benefit obligation is 16.7 years. There is no maturity profile since the average 
remaining life before active employees reach final age according to the plan is 9.3 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, 2024
For the year ended
December 31, 2023
Opening balance 21,690 13,604
Ordinary contributions paid by employer 906 925
Ordinary contributions paid by employees 604 617
Additional contributions paid by employees 1,340 6,685
Interest income on plan assets 392 315
Return on plan assets excluding interest income (101) (155)
Foreign exchange gain/(loss) (1,507) 1,834
Benefits paid from plan assets (7,440) (2,135)
Fair value of plan assets, ending balance 15,884 21,690
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, 2024
For the year ended
December 31, 2023
Current service cost 608 423
Interest expense on defined benefit obligation 402 322
Administration costs 18 16
Past service cost 46 –
Interest income on plan assets (392) (315)
Total expense recognized 682 446
The expense associated with the Group’s pension plan of USD 682 thousand was included within general and administrative 
expenses. The Group also recognized in other comprehensive income a USD 3,491 thousand net actuarial loss 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, 2024
For the year ended
December 31, 2023
Discount rate 1.00% 1.90%
Inflation rate 1.00% 1.25%
Future salary increase 1.25% 1.25%
Future pension increases 0.00% 0.00%
Retirement ages, male (‘M’) and female (‘F’) M65/F65 M65/F64
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 7.4% Increase by 8.4%
Salary growth rate 0.50% Increase by 0.4% Decrease by 0.4%
Life Expectancy One year Increase by 1.3% Decrease by 1.4%
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.

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

36
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
21. TRADE AND OTHER PAYABLES
USD Thousands December 31, 2024 December 31, 2023
Trade payables  42,634    42,761
Joint operations creditors  11,671    22,257
Accrued expenses  119,316    118,912
Other  2,750    4,941
 176,371    188,871
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, 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 accounting policies for financial instruments have been applied to the line items below:
December 31, 2023
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 41,486 41,486 – –
Derivative instruments 42,553 – – 42,553
Joint operation debtors 910 910 – –
Other current receivables2 104,315 103,286 1,029 –
Cash and cash equivalents 517,074 517,074 – –
Financial assets 706,338 662,756 1,029 42,553
1 See Note 11
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.

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

37
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
December 31, 2023
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 440,483 440,483 – –
Current financial liabilities 3,589 3,589 – –
Derivative instruments 1,530 – – 1,530
Joint operation creditors 22,257 22,257 – –
Other current liabilities 166,869 166,869 – –
Financial liabilities 634,728 633,198 – 1,530
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.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
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
December 31, 2023
USD Thousands Level 1 Level 2 Level 3
Other current receivables 1,029 – –
Derivative instruments – current – 35,504 –
Derivative instruments – non-current – 7,049 –
Financial assets 1,029 42,553 –
Derivative instruments – current – 1,267 –
Derivative instruments – non-current – 61 202
Financial liabilities – 1,328 202
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, 2024, 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, 2024, the trade receivables amounted to USD 94,265 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.

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

38
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
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.
USD Thousands December 31, 2024 December 31, 2023
Non-current  
Repayment within 1- 5 years:
  - Bank loans 1,719 5,442 
  - Bonds1 443,407 440,288 
445,126 445,730
Current
Repayment within 12 months:
 - Bank loans 3,402 3,589
Payment within 6 months:
  - Trade payables 42,634 42,761 
  - Joint operation creditors 11,671 22,257 
  - Other current liabilities 2,750 4,941 
  - Current tax liabilities 1,146 255 
61,603 73,803 
1 The bonds redeemable value at maturity in February 2027 is USD 450 million.  
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 entered into currency hedges to purchase :
(i) a total CAD 520 million for the period January 2025 to December 2025 at an average rate of CAD 1.36 (sell USD); 
(ii) a total EUR 27 million for the period January 2025 to December 2025 at an average rate of EUR 1.07 (sell USD); 
(iii) a total MYR 138 million for the period January 2025 to December 2025 at an average rate of MYR 4.40 (sell USD).
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.

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

39
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
The outstanding derivative instruments can be specified as follows:
Fair value of outstanding derivative instruments in the balance sheet
USD Thousands
December 31, 2024 December 31, 2023
Assets Liabilities Assets Liabilities
Currency hedge - CAD – 19,030 13,644 1,328
Currency hedge - EUR – 557 – –
Currency hedge - MYR – 282 618 –
Total – 19,869 14,262 1,328
Non-current – – 7,049 61
Current – 19,869 7,213 1,267
Total – 19,869 14,262 1,328
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, 2024 and 2023.
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)
Shift of currency exchange rates
USD Thousands
Average rate
2023
USD weakening
10%
USD strengthening 
10%
Gross profit in the financial statements 250,514 250,514
EUR/USD 0.9246 0.8405 1.0170
CAD/USD 1.3496 1.2269 1.4846
Total effect on gross profit 20,700 (20,700)
 
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, 2024 and 2023, AUDITED
The Group had oil price sale financial hedges outstanding as at December 31, 2024, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
January 1, 2025 - December 31, 2025 11,700 WTI/WCS Differential USD -14.26/bbl
January 1, 2025 - March 31, 2025 5,000 WTI Sale Swap USD 70.00/bbl
April 1, 2025 - June 30, 2025 2,500 WTI Sale Swap USD 70.00/bbl
The Group had gas price sale financial hedges outstanding as at December, 2024 which are summarized as follows:
Period Volume (Gigajoules (GJ) per 
day)) Type Average Pricing 
January 1, 2025 - December 31, 2025 10,000 AECO Swap CAD 2.500/GJ
The Group had electricity financial hedges outstanding as at December 31, 2024, which are summarized as follows:
Period Volume (MW) Type Average Pricing 
October 1, 2025 – 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, 2024 December 31, 2023
Assets Liabilities Assets Liabilities
Oil price hedge 1,949 28,291
Gas price hedge 1,270 – – –
Electricity price hedge – 562 – 202
Total 3,219 562 28,291 202
Non-current – 562 – 202
Current 3,219 – 28,291 –
Total 3,219 562 28,291 202
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, 2024 
and 2023:
2024 net result (USD Thousands) 102,219 102,219
Possible shift (%) (10%) 10%
Total effect on net result (USD Thousands) (65,653) 65,653
2023 net result (USD Thousands) 172,979 172,979
Possible shift (%) (10%) 10%
Total effect on net result (USD Thousands) (60,010) 60,010
e) Interest rate risk 
The Group’s exposure to interest rate risk arises from the interest rate impact on its debt facilities. As at December 31, 2024, the 
Group’s long-term debt is mainly comprised of a fixed coupon rate of 7.25%. As such, changes in the interest rate will not have a 
significant adverse impact on interest expense.

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

41
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, 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, 2024 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 compensation expenses
The following table provides a breakdown of gross salaries, short-term benefits, share-based compensation and other compensation 
expenses included in the consolidated statement of comprehensive income:
USD Thousands 2024 2023
Salaries, bonuses and other short-term benefits 53,370 57,280
Security social costs 6,988 7,100
Share-based incentive plans1 8,539 11,690
68,897 76,070
1 Vested during the year and based on IFRS 2 valuation (see Note 17)
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 2024 2023
Directors’ fees 900 665
Senior Management’s salaries, bonuses and other short-term benefits 6,196 8,198
Share-based incentive plans paid to Senior Management 15,155 7,933
22,251 16,796
26. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In the normal course of business, the Group has committed to certain payments which are not recognised as liabilities. The 
following table summarizes the Group’s commitments in Canada as at December 31, 2024:
CAD Millions 2025 2026 2027 2028 2029 Thereafter
Transportation service1 33.3 60.6 89.2 92.8 96.7 1,391.6
Power2 14.5 12.4 12.4 9.8 – –
Total commitments 47.8 73.0 101.6 102.6 96.7 1,391.6
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2045.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from January 1, 2025 to December 
31, 2028, an additional 5MWh at a weighted average price of CAD 58.31/MWh from January 1, 2025 to December 31, 2027, and an additional 
5MWh at a weighted average price of CAD 46.85/MWh from January 1, 2025 to December 31, 2025.

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

42
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024 and 2023, AUDITED
27. RELATED PARTIES
During the year 2024, the Group paid USD 444 thousand to the Lundin Foundation in respect of sustainability advisory services 
provided to the Group and USD 834 thousand to Orrön Energy in respect of office space rental. 
During the year 2024, Orrön Energy and ShaMaran Petroleum Corp. paid respectively USD 546 thousand and USD 186 thousand to 
the Group in respect of support services provided during the year 2024.
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.
28. SUBSEQUENT EVENTS
In January 2025, the Group entered into the following oil price sale financial hedges:
Period Volume (barrels per day) Type Average Pricing 
January 1, 2025 - January 31, 2025 2,000 WTI Sale Swap USD 72.00/bbl
February 1, 2025 - March 31, 2025 5,000 WTI Sale Swap USD 72.60/bbl
April 1, 2025 - June 30, 2025 7,500 WTI Sale Swap USD 71.73/bbl
July 1, 2025 - December 31, 2025 10,000 WTI Sale Swap USD 71.30/bbl
January 1, 2025 - January 31, 2025 1,000 Brent Sale Swap USD 75.00/bbl
February 1, 2025 - December 31, 2025 2,000 Brent Sale Swap USD 75.78/bbl
No other events have occurred since December 31, 2024, that are expected to have a substantial effect on this report.

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

Corporate Office
International Petroleum Corp
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 ended and year ended
December 31, 2024

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
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 22.
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 38.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada are effective as of December 
31, 2024, and are included in the reports prepared by Sproule Associates Limited (Sproule), an independent qualified reserves evaluator, 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’s December 31, 2024, price forecasts. 
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in France and Malaysia are effective as of 
December 31, 2024, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), an independent qualified reserves auditor, in accordance with NI 51-101 and 
the COGE Handbook, and using Sproule’s December 31, 2024, 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  12
• Financial Results 12
• Capital Expenditure 21
• Financial Position and Liquidity  21
• Non-IFRS Measures 22
• Off-Balance Sheet Arrangements  24
• Outstanding Share Data  24
• Contractual Obligations and Commitments  25
• Material Accounting Policies and Estimates 25
• Transactions with Related Parties  26
• Financial Risk Management  26
RISK FACTORS 28
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING  38
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION  38
RESERVES AND RESOURCES ADVISORY  40
OTHER SUPPLEMENTARY INFORMATION 42
2

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
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 11, 2025 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, 2024 (“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, 2024 December 31, 2023
Average Year end Average Year end
1 EUR equals USD 1.0821 1.0389 1.0816 1.1050
1 USD equals CAD 1.3698 1.4388 1.3496 1.3251
1 USD equals MYR 4.5759 4.4715 4.5598 4.5950
              
IPC completed the acquisition of Cor4 Oil Corp. (“Cor4”) on March 3, 2023. In accordance with IFRS, the Financial Statements for 
periods in 2023 have been prepared on that basis, with revenues and expenses related to the Brooks assets acquired in the Cor4 
acquisition included in the Financial Statements from March 3, 2023. Certain 2023 operational and financial information included 
in the MD&A, including production, operating costs, OCF , FCF and EBITDA related to the Brooks assets acquired in the Cor4 
acquisition, are reported based on the effective date of the Cor4 acquisition of January 1, 2023. See also “Operations Overview – 
Production” and “Non-IFRS Measures” below.
3

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
HIGHLIGHTS
2024 Business Highlights
• Average net production of approximately 47,400 boepd for the fourth quarter of 2024 was in line with the guidance range for 
the period (51% heavy crude oil, 15% light and medium crude oil and 34% natural gas).(1) 
• Full year 2024 average net production was 47,400 boepd, above the mid-point of the 2024 annual guidance of 46,000 to 
48,000 boepd.(1)
• Development activities on Phase 1 of the Blackrod project progressed in 2024 on schedule and on budget, with forecast first 
oil in late 2026. All major third-party contracts have been executed and construction is advancing according to plan, including 
construction of the central processing facility (CPF) and well pad facilities, finalization of the midstream agreements for the 
input fuel gas, diluent and oil blend pipelines, and advancement of drilling operations. As at the end of 2024, over two-thirds 
of the forecast Blackrod Phase 1 development capital expenditure of USD 850 million has been spent since project sanction 
in early 2023. 
• Drilling activity at the Southern Alberta assets in Canada continued with a total of thirteen wells drilled during 2024. 
• Successful completion of planned maintenance shutdowns at Onion Lake Thermal (OLT) in Canada and the Bertam field in 
Malaysia during 2024. 
• 8.3 million common shares purchased and cancelled from December 2023 to early December 2024 under IPC’s 2023/2024 
NCIB and a further 2.2 million common shares purchased for cancellation during December 2024 and January 2025 under the 
renewed 2024/2025 NCIB. 
• In Q3 2024, published IPC’s fifth annual Sustainability Report.
 
2024 Financial Highlights
• Operating costs per boe of USD 18.2 for the fourth quarter of 2024 and USD 17.0 for the full year, in line with the most 
recent 2024 guidance of less than USD 18 per boe for the full year.(3)
• Strong operating cash flow (OCF) generation for the fourth quarter and full year 2024 amounted to MUSD 78 and MUSD 
342, respectively.(3)
• Capital and decommissioning expenditures of MUSD 129 for the fourth quarter and MUSD 442 for the full year 2024, in line 
with the full year guidance of MUSD 437.
• Free cash flow (FCF) generation for the full year 2024 of negative MUSD 135, with negative FCF generation of MUSD 61 for 
the fourth quarter in line with expectations and taking into account the significant capital expenditures during the quarter in 
respect of the Blackrod project. FCF for the full year 2024, before 2024 Blackrod Phase 1 development expenditure of MUSD 
351, was MUSD 216.(3)
• Net debt of MUSD 209 and gross cash of MUSD 247 as at December 31, 2024. (3)
• Net result of MUSD 0.4 for the fourth quarter of 2024 and MUSD 102 for the full year 2024.
• Entered into a letter of credit facility in Canada during 2024 to cover operational letters of credit, giving full availability under 
IPC’s undrawn CAD 180 million Revolving Credit Facility.
Reserves and Resources
• Total 2P reserves as at December 31, 2024 of 493 MMboe, with a reserve life index (RLI) of 31 years. (1)(2)
• Contingent resources (best estimate, unrisked) as at December 31, 2024 of 1,107 MMboe.(1)(2)
• 2P reserves net asset value (NAV) as at December 31, 2024 of MUSD 3,083 (10% discount rate).(1)(2)(5)(6)
2025 Annual Guidance
• Full year 2025 average net production forecast at 43,000 to 45,000 boepd. (1)
• Full year 2025 operating costs forecast at USD 18 to 19 per boe.(3)
• Full year 2025 OCF guidance estimated at between MUSD 210 and 280 (assuming Brent USD 65 to 85 per barrel). (3)
• Full year 2025 capital and decommissioning expenditures guidance forecast at MUSD 320, including MUSD 230  relating to 
Blackrod capital expenditure.
• Full year 2025 FCF ranges from approximately MUSD 80 to 150 (assuming Brent USD 65 to 85 per barrel) before taking into account 
proposed Blackrod capital expenditures, or negative MUSD 150 to 80 including proposed Blackrod capital expenditures.(3)
Business Plan Production and Cash Flow Guidance
• 2025 – 2029 business plan forecasts:
• average net production forecast approximately 57,000 boepd. (1)(8)
• capital expenditure forecast of USD 8 per boe, including USD 3 per boe for growth expenditures. (8)
• operating costs forecast of USD 18 to 19 per boe.(3)(8)
• FCF forecast of approximately MUSD 1,200 to 2,000 (assuming Brent USD 75 to 95 per barrel). (3)(8)
• 2030 – 2034 business plan forecasts:
• average net production forecast of approximately 63,000 boepd. (1)(8)
• capital expenditure forecast of USD 5 per boe.(8)
• operating costs forecast of USD 18 to 19 per boe.(3)(8)
• FCF forecast of approximately MUSD 1,600 to 2,600 (assuming Brent USD 75 to 95 per barrel). (3)(8)
4

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Three months ended 
December 31
Year ended 
December 31
USD Thousands 2024 2023 2024 2023
Revenue 199,124 198,460 797,783 853,906
Gross profit 42,774 39,955 210,171 250,514
Net result 415 29,710 102,219 172,979
Operating cash flow(3) 78,158 73,634 341,989 353,048
Free cash flow(3) (61,476) (64,688) (135,497) 2,689
EBITDA(3) 76,184 66,284 335,488 350,618
Net cash/(debt)(3) (208,528) 58,043 (208,528) 58,043
5

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
OPERATIONS REVIEW 
Business Overview
IPC was launched in 2017 by way of spinning off the non-Norwegian assets from Lundin Energy. The strategy and vision from 
the outset was to be the international E&P growth vehicle for the Lundin Group by pursuing growth organically and through 
acquisitions. The foundation of this strategy was and is predicated on maximising long-term stakeholder value through responsible 
business operations focused on operational excellence and financial resilience to underpin optimal capital allocation decision- 
making.  
 
We are very pleased with the track record of value creation achieved by the company to date. IPC’s production, reserves, 
resources and cash flow exposure has increased materially through accretive acquisitions supplemented by base business 
investment. Excluding the growth capital expenditure assigned to the Blackrod Phase 1 development, over USD 1.5 billion in free 
cash flow (FCF) has been generated and over USD 0.5 billion has been returned to shareholders in the form of share buybacks 
since inception. IPC’s current shares outstanding are less than 5% higher than the original shares outstanding upon the formation 
of the company. IPC is determined to build on the historical success and the growth outlook has never been brighter.(3)
2024 was a milestone year for the company through successfully delivering the largest capital investment campaign in its history. 
The record investment was accompanied by strong safety, operational and financial performance. IPC returned USD 102 million of 
value to shareholders in the year through share repurchases, whilst maintaining a strong balance sheet.
Oil prices were rangebound in 2024 between Brent USD 70 to 90 per barrel, with a full year Brent average of USD 81 per barrel, 
in line with our original oil price sensitivities guided at CMD. The fourth quarter 2024 Brent price averaged USD 75 per barrel, the 
lowest quarterly price average in the year. The downward trend in benchmark oil prices through the second half of 2024 has been 
slightly reversed in current time as continuous crude inventory draws, strong demand, underwhelming non-OPEC production 
growth and continued OPEC production curtailments have supported the market balance. A new administration in the White 
House presents uncertainty for the oil market, as looming tariffs and sanctions pose a risk to global supply chain systems and trade 
flows. Around 40% of our 2025 Dated Brent and WTI exposure is hedged at USD 76 per barrel and USD 71 per barrel respectively.
The fourth quarter 2024 WTI to WCS price differentials averaged less than USD 13 per barrel, around USD 2 per barrel lower 
than the full year average of USD 15 per barrel. The fourth quarter differential was the lowest quarterly average since the Covid 
pandemic in 2020 when benchmark oil prices were more than USD 30 per barrel less than current levels. The TMX pipeline is 
driving the tighter differentials with excess take-away capacity in the Western Canadian Sedimentary Basin (WCSB) relative 
to supply. Close to 50% of our 2025 WCS to WTI differential exposure is hedged at USD 14 per barrel, which should assist in 
mitigating adverse effects of potential US tariffs on Canadian production.
Natural gas prices averaged CAD 1.5 per Mcf for 2024 and in the fourth quarter. Western Canada gas storage levels continue to sit 
above the five-year range. This is in part due to delays of the LNG Canada start-up project which was supposed to be onstream at 
end 2024, start-up is now anticipated for mid-2025. IPC has around 9,600 Mcf per day hedged at CAD 2.6 per Mcf for 2025.
Fourth Quarter and Full Year 2024 Highlights
During the fourth quarter of 2024, IPC’s assets delivered average net production of 47,400 boepd, in line with guidance for the 
quarter. Full year 2024 average net production of 47,400 boepd was above the 2024 mid-point guidance range of 46,000 to 48,000 
boepd.(1)
IPC’s operating costs per boe for the fourth quarter of 2024 was USD 18.2. Full year 2024 operating costs per boe was USD 17.0, 
in line with the most recent 2024 annual guidance of less than USD 18 per boe.(3)
Operating cash flow (OCF) generation for the fourth quarter of 2024 was USD 78 million. Full year 2024 OCF was USD 342 million 
in line with the most recent guidance of USD 335 to 342 million.(3)
Capital and decommissioning expenditure for the fourth quarter of 2024 was USD 129 million. Full year 2024 capital and 
decommissioning expenditure of USD 442 million was in line with guidance of USD 437 million.
Free cash flow (FCF) generation was in line with guidance at negative USD 61 million during the fourth quarter of 2024, reflecting 
the higher level of capital expenditure on the Blackrod Phase 1 development project. Full year 2024 FCF generation was negative 
USD 135 million, in line with the most recent guidance of negative USD 140 to 133 million.(3)
As at December 31, 2024, IPC’s net debt position was USD 209 million. IPC’s gross cash on the balance sheet amounts to USD 
247 million which provides IPC with significant financial strength to continue progressing its strategies in 2025, including advancing 
the Blackrod development project, returning value to shareholders through the 2024/2025 NCIB, and remaining opportunistic to 
mergers and acquisitions activity.(3)
6

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Blackrod Project
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 Steam Assisted Gravity Drainage (SAGD) development in the first quarter of 2023. The Phase 1 development targets 
259 MMboe of 2P reserves, with a multi- year forecast capital expenditure of USD 850 million to first oil planned in late 2026. The 
Phase 1 development is planned for plateau production of 30,000 bopd which is expected by early 2028.(1)(2) 
As at the end of 2024, USD 591 million of cumulative growth capital, has been spent on the Blackrod Phase 1 development since 
sanction with a peak annual investment of USD 351 million incurred in 2024. Significant progress has been made across all key 
scopes of the project including but not limited to: detailed engineering, procurement, fabrication, drilling, construction, third party 
transport pipelines, commissioning and operations planning. Site health and safety control has been excellent with zero lost time 
incidents since commercial development activities commenced.
Looking forward, USD 230 million is planned to be spent in 2025 mainly relating to advancing the remaining fabrication, 
construction and substantial completion of the Central Processing Facility (CPF) for the Phase 1 development. The remaining 
growth capital expenditure to first oil is forecast to be spent in 2026 on drilling, completions and commissioning of the CPF with 
first steam anticipated by end Q1 2026.
IPC is strongly positioned to deliver within plan with a clear line of sight to start-up. The Blackrod Phase 1 project is expected to 
generate significant value for all our stakeholders. And with over 1 billion barrels of best estimate contingent resources (unrisked) 
beyond Phase 1, IPC is pleased to announce a resource maturation plan that sees significant volume maturation into reserves 
through low cost of less than USD 0.15 per barrel. The 2P reserves attributable to Phase 1 has increased by 40 MMboe to 259 
MMboe from year end 2023 to year end 2024.(2)
As at the end of 2024, 70% of the Blackrod Phase 1 development capital had been spent since the project sanction in early 
2023. All major work streams are progressing as planned and the focus continues to be on executing the detailed sequencing of 
events as facility modules are safely delivered and installed at site. The total Phase 1 project guidance of USD 850 million capital 
expenditure to first oil in late 2026 is unchanged. IPC intends to fund the remaining Blackrod Phase 1 development costs with 
forecast cash flow generated by its operations and cash on hand.
Stakeholder Returns: Normal Course Issuer Bid
During the period of December 5, 2023 to December 4, 2024, IPC purchased and cancelled an aggregate of approximately 8.3 
million common shares under the 2023/2024 NCIB. The average price of shares purchased under the 2023/2024 NCIB was SEK 
131 / CAD 17 per share.
In Q4 2024, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 7.5 million common 
shares over the period of December 5, 2024 to December 4, 2025. Under the 2024/2025 NCIB, IPC repurchased and cancelled 
approximately 0.8 million common shares in December 2024. By the end of January 2025, IPC repurchased for cancellation over 
1.4 million common shares under the 2024/2025 NCIB. The average price of common shares purchased under the 2024/2025 
NCIB during December 2024 and January 2025 was SEK 135 / CAD 17.5 per share.
As at February 7, 2025, IPC had a total of 117,781,927 common shares issued and outstanding, of which IPC holds 508,853 
common shares in treasury. 
Under the 2024/2025 NCIB, IPC may purchase and cancel a further 5.3 million common shares by December 4, 2025. This would 
result in the cancellation of 6.2% of shares outstanding as at the beginning of December 2024. IPC continues to believe that 
reducing the number of shares outstanding while in parallel investing in material production growth at Blackrod will prove to be a 
winning formula for our stakeholders.
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 2024, IPC recorded no material safety or environmental 
incidents.  
As previously announced, IPC targets a reduction of our net GHG emissions intensity by the end of 2025 to 50% of IPC’s 2019 
baseline and IPC remains on track to achieve this reduction. During 2024, IPC announced the commitment 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 2024, IPC’s 2P reserves are 493 MMboe. During 2024, IPC replaced 251% of the annual 2024 
production. The reserve life index (RLI) as at December 31, 2024, is approximately 31 years.(1)(2)
The net present value (NPV) of IPC’s 2P reserves as at December 31, 2024 was USD 3.3 billion. IPC’s net asset value (NAV) was 
USD 3.1 billion or SEK 287 / CAD 37 per share as at December 31, 2024.(1)(2)(5)(6)(7)
In addition, IPC’s best estimate contingent resources (unrisked) as at December 31, 2024 are 1,107 MMboe, of which 1,025 
MMboe relate to future potential phases of the Blackrod project.(1)(2)
7

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
2025 Budget and Operational Guidance
IPC is pleased to announce its 2025 average net production guidance is 43,000 to 45,000 boepd. IPC forecasts operating costs for 
2025 between USD 18 and 19 per boe.(1)(3)
IPC’s 2025 capital and decommissioning expenditure budget is USD 320 million, with USD 230 million forecast relating to Blackrod 
capital expenditure. The remainder of the 2025 budget in Canada includes drilling and ongoing optimization work at Onion Lake 
Thermal and Suffield Area assets. IPC also plans to advance the next phase of infill drilling and complete well maintenance works 
at the Bertam field in Malaysia. IPC expects to conduct technical studies for future development potential in France. 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 
2025.
Notwithstanding a modest production decline expected in 2025, IPC’s production per share metric remains largely unchanged 
relative to 2024 and 2023. IPC has prioritised capital allocation to the transformational Blackrod Phase 1 development and share 
buybacks as opposed to further increasing its base business investment to preserve balance sheet strength and maximise long-
term shareholder value.
Further details regarding IPC’s proposed 2025 budget and operational guidance will be provided at IPC’s Capital Markets Day 
presentation to be held on February 11, 2025 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 493 MMboe as at December 31, 2024, by the 
mid-point of the 2025 CMD production guidance of 43,000 to 45,000 boepd. Reserves replacement ratio is based on 2P 
reserves of 468 boe as at December 31, 2024, sales production during 2024 of 16.6 MMboe, net additions to 2P reserves 
during 2024 of 41.7 MMboe, and 2P reserves of 493 MMboe as at December 31, 2024.  
(3) Non-IFRS measure, see “Non-IFRS Measures” below and in the MD&A.
(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 209 million as at December 31, 2024.
(7) NAV per share is based on 119,059,315 IPC common shares as at December 31, 2024, being 119,169,471 common shares 
outstanding less 110,156 common shares held in treasury and cancelled in January 2025. NAV per share is not predictive 
and may not be reflective of current or future market prices for IPC common shares.
(8) Estimated FCF generation is based on IPC’s current business plans over the periods of 2025 to 2029 and 2030 to 
2034, including net debt of USD 209 million as at December 31, 2024, with assumptions based on the reports of 
IPC’s independent reserves evaluators, and including certain corporate adjustments relating to estimated general and 
administration costs and hedging, and excluding shareholder distributions and financing costs. Assumptions include average 
net production of approximately 57 Mboepd over the period of 2025 to 2029, average net production of approximately 63 
Mboepd over the period of 2030 to 2034, average Brent oil prices of USD 75 to 95 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 as further described in the MCR. IPC’s market capitalization is at close on January 31, 2025 (USD 1,557 
million based on 146.8 SEK/share, 117.7 million IPC shares outstanding (net of treasury shares) and exchange rate of 11.10 
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 ended and year ended December 31, 2024
Operations Overview 
2024 Overview
In 2024, IPC continued to successfully demonstrate its commitment to operational excellence, delivering annual net average daily 
production above the mid-point of our Capital Markets Day (CMD) guidance with no material safety or environmental incidents 
recorded in the year. 
In Canada, the Blackrod Phase 1 development project is progressing in line with schedule and budget. Process facility fabrication 
is on track supporting critical equipment site installation which continues to progress in line with plan. Access road upgrades have 
been completed and third-party transport pipeline installation is progressing on schedule. Production well pad drilling continues and 
is ahead of schedule. At Onion Lake Thermal, daily production has remained stable with three additional production sustaining Pad 
L well pairs brought online in 2024. A total of seven Pad L well pairs are now online. At Suffield, all eight budgeted Ellerslie play 
production wells have been brought online and are producing in line with expectations. At Ferguson, the three new oil production 
wells continue to deliver above expectations. During Q4, on the back of the positive results, IPC sanctioned and drilled two 
additional Ferguson production wells. The wells are expected to be online early in Q1 2025. 
In Malaysia and France, field development studies have progressed as planned.
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 493 MMboe as at December 31, 2024, as certified by independent 
third party reserve auditors. The proved plus probable reserve life index (RLI) as at December 31, 2024, is approximately 31 years. 
Best estimate contingent resources as at December 31, 2024, are 1,107 MMboe (unrisked). See “Reserves and Resources 
Advisory” below. 
Production
Average daily net production for Q4 2024 was in line with the CMD guidance at 47,400 boepd. In Canada, strong operational 
performance has been supported by increased gas production rates with re-initiation of base gas optimization activity. At the 
Bertam field in Malaysia, average daily production remained strong in Q4 2024, with high production uptime and a continued focus 
on well rate optimization activity to offset natural declines. In France, stable production performance continued through Q4 2024.
With strong operational delivery through 2024, IPC’s exits the year with a net average daily production for 2024 above the mid-
point of our CMD guidance at 47,400 boepd.
The production during Q4 2024 with comparatives is summarized below:
Production
in Mboepd
Three months ended
December 31
Year ended
December 31
2024 2023 2024 2023
Crude oil
Canada – Northern Assets 14.6 15.5 14.2 15.5
Canada – Southern Assets1 11.2 11.4 11.1 11.8
Malaysia 3.5 2.5 3.8 3.8
France 2.1 2.8 2.4 2.8
Total crude oil production 31.4 32.2 31.5 33.9
Gas
Canada – Northern Assets 0.5 0.4 0.5 0.4
Canada – Southern Assets 15.5 17.0 15.4 16.8
Total gas production 16.0 17.4 15.9 17.2
Total production 47.4 49.6 47.4 51.1
Quantity in MMboe 4.36 4.56 17.34 18.65
1 In respect of 2023 production, includes production from the Brooks assets acquired in the Cor4 acquisition in the Suffield area from January 1, 
2023 being the effective date of the Cor4 acquisition. The acquisition of Cor4 was completed on March 3, 2023. 
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
9

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
CANADA
Production
in Mboepd
Working 
Interest
(WI)
Three months ended
December 31
Year ended
December 31
2024 2023 2024 2023
- Oil Onion Lake Thermal 100% 12.2 13.6 12.3 13.3
- Oil Suffield Area1 100% 9.8 10.1 9.7 10.2
- Oil Other 50-100% 3.8 3.2 3.3 3.8
- Gas1 ~100% 16.0 17.4 15.9 17.2
Canada 41.8 44.3 41.2 44.5
1  In respect of 2023 production, includes production from the Brooks assets acquired in the Cor4 acquisition in the Suffield area from January 1, 
2023 being the effective date of the Cor4 acquisition. The acquisition of Cor4 was completed on March 3, 2023. 
 
Production
Net production from IPC’s assets in Canada during Q4 2024 was in line with guidance at 41,800 boepd. Strong operational 
performance has been supplemented by base gas optimization activity recommencing and positive results from the recent oil 
well drilling in the Southern Alberta assets. At the Mooney asset, the Phase 2 enhanced oil recovery polymer flood project has 
performed ahead of expectations. Production remains stable at Onion Lake Thermal as the production wells from the latest 
production sustaining Pad L are phased in.
Organic Growth and Capital Projects
In Canada, with the Blackrod Phase 1 project development in its most capital-intensive phase, IPC announced a minimum non-
Blackrod capital expenditure budget for 2024. At our Southern assets, the focus remains on the high performing Suffield Ellerslie 
play and is supplemented with the next phase of development well drilling at our Ferguson asset. At Onion Lake Thermal, 
production rate optimization is the priority with a continued phased ramp up of the latest production sustaining Pad L.
The Blackrod Phase 1 development project is progressing in line with schedule and budget. As at the end of Q4 2024, process 
facility fabrication is on track supporting critical equipment site installation which continues to progress in line with plan. Access 
road upgrades have been completed and third-party transport pipeline installation is progressing on schedule. Production well pad 
drilling continues and remains ahead of schedule. 
At Ferguson, the three 2024 drilled oil production wells continue to deliver ahead of expectations. On the back of the positive 
results, IPC sanctioned drilling of an additional two Ferguson wells in Q4 2024. The wells have been drilled and are expected to be 
online in Q1 2025.
During Q4 2024, IPC completed drilling of the final Suffield area Ellerslie well target in the year. As of the end of Q4 2024, all eight 
2024 sanctioned Ellerslie wells have been drilled and are online and performing in line with expectations. 
At Onion Lake Thermal, daily production has remained stable with the seventh production sustaining Pad L well pair brought online 
in the quarter. 
MALAYSIA
Production
in Mboepd WI
Three months ended
December 31
Year ended
December 31
2024 2023 2024 2023
Bertam 100% 3.5 2.5 3.8 3.8
Production
Net production at Bertam in Malaysia in Q4 2024 was in line with guidance at 3,500 boepd with one production well offline late in 
December awaiting workover intervention.
Organic Growth and Capital Projects
In Malaysia, field development studies have progressed in line with expectations. During 2025, IPC plans to advance the next 
phase of infill drilling and complete well maintenance works at the Bertam field.
10

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
FRANCE
Production
in Mboepd WI
Three months ended
December 31
Year ended
December 31
2024 2023 2024 2023
France
- Paris Basin 100%1 1.8 2.5 2.1 2.4
- Aquitaine 50% 0.3 0.3 0.3 0.4
2.1 2.8 2.4 2.8
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q4 2024 was at 2,100 boepd with stable performance at all the major producing assets.   
Organic Growth
IPC continues to mature future development projects in France, with the next phase of production well targets matured and ready 
for sanction decision at the company’s discretion.
11

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
FINANCIAL REVIEW 
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands 2024 2023 2022
Revenue 797,783 853,906 1,129,298
Gross profit 210,171 250,514 516,709
Net result 102,219 172,979 337,725
Earnings per share – USD 0.82 1.31 2.30
Earnings per share fully diluted – USD 0.81 1.28 2.25
Operating cash flow1 341,989 353,048 622,947
Free cash flow1 (135,497) 2,689 430,242
EBITDA1 335,488 350,618 639,480
Net cash / (debt) at period end1 (208,528) 58,043 175,098
1  See definition on page 22 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands December 31, 2024 December 31, 2023 December 31, 2022
Non-current assets 1,554,833 1,372,388 1,041,051
Current assets 398,849 690,597 638,566
Total assets 1,953,682 2,062,985 1,679,617
Total non-current liabilities 806,134 779,838 564,381
Current liabilities 208,078 202,888 149,905
Total liabilities 1,014,212 982,726 714,286
Net assets 939,470 1,080,259 965,331
Working capital (including cash) 190,771 487,709 488,661
12

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Selected Interim Financial Information
Selected interim condensed consolidated statement of operations is as follows:
USD Thousands 2024 Q4-24 Q3-24 Q2-24 Q1-24 2023 Q4-23 Q3-23 Q2-23 Q1-23
Revenue 797,783 199,124 173,200 219,040 206,419 853,906 198,460 257,366 205,564 192,516
Gross profit 210,171 42,774 39,505 72,708 55,184 250,514 39,955 93,429 52,747 64,383
Net result 102,219 415 22,875 45,210 33,719 172,979 29,710 71,681 32,025 39,563
Earnings per share – 
USD 0.82 0.00 0.19 0.36 0.27 1.31 0.23 0.56 0.24 0.29
Earnings per share fully
diluted – USD 0.81 0.00 0.18 0.36 0.26 1.28 0.22 0.54 0.24 0.28
Operating cash flow1 341,989 78,158 72,589 101,941 89,301 353,048 73,634 119,142 84,372 75,900
Free cash flow1 (135,497) (61,476) (38,269) 7,559 (43,311) 2,689 (64,688) 34,703 16,415 16,259
EBITDA1 335,488 76,184 68,313 103,971 87,020 350,618 66,284 123,054 85,201 76,079
Net cash/(debt) at 
period end1 (208,528) (208,528) (157,228) (88,220) (60,572) 58,043 58,043 83,097 63,548 66,956
1 See definition on page 22 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, 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
13

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Three months ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 105,268 62,240 15,313 28,617 – 211,438
NGLs – 327 – – – 327
Gas 118 14,656 – – – 14,774
Net sales of oil and gas 105,386 77,223 15,313 28,617 – 226,539
Change in under/over lift 
position – – – (8,442) – (8,442)
Royalties (14,657) (10,807) – (1,545) – (27,009)
Hedging settlement 3,205 3,754 – – – 6,959
Other operating revenue – – – 228 185 413
Revenue 93,934 70,170 15,313 18,858 185 198,460
Operating costs (23,868) (38,651) (9,170) (11,679) – (83,368)
Cost of blending (37,601) (6,872) – – – (44,473)
Change in inventory position (638) 873 1,217 (25) – 1,427
Depletion and decommissioning 
costs (9,165) (14,654) (2,982) (3,633) – (30,434)
Depreciation of other tangible 
fixed assets – – (1,309) – – (1,309)
Exploration and business
development costs – – – (30) (318) (348)
Gross profit/(loss) 22,662 10,866 3,069 3,491 (133) 39,955
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
14

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Year ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 430,231 258,660 101,237 81,093 – 871,221
NGLs – 1,172 – – – 1,172
Gas 373 66,965 – – – 67,338
Net sales of oil and gas 430,604 326,797 101,237 81,093 – 939,731
Change in under/over lift position – – – 400 – 400
Royalties (60,152) (41,025) – (5,120) – (106,297)
Hedging settlement 1,585 17,343 – – – 18,928
Other operating revenue – 7 – 867 270 1,144
Revenue 372,037 303,122 101,237 77,240 270 853,906
Operating costs (94,817) (155,178) (35,679) (36,288) – (321,962)
Cost of blending (146,204) (26,792) – – – (172,996)
Change in inventory position (448) 952 3,358 (207) – 3,655
Depletion and decommissioning 
costs1 (24,969) (45,135) (17,800) (14,018) – (101,922)
Depreciation of other tangible 
fixed assets – – (7,812) – – (7,812)
Exploration and business
development costs – (834) – (39) (1,482) (2,355)
Gross profit/(loss) 105,599 76,135 43,304 26,688 (1,212) 250,514
1  In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program.
Three months and year ended December 31, 2024, Review 
Revenue
Total revenue amounted to USD 199,124 thousand for Q4 2024, compared to USD 198,460 thousand for Q4 2023 and USD
797,783 thousand for the year ended December 31, 2024 compared to USD 853,906 thousand for the year ended December 31, 
2023 and is analyzed as follows: 
USD Thousands 
Three months ended 
December 31
Year ended
December 31
2024 2023 2024 2023
Crude oil sales 211,051 211,438 854,487 871,221
Gas and NGL sales 9,224 15,101 34,967 68,510
Change in under/overlift position (6,379) (8,442) 41 400
Royalties (25,559) (27,009) (115,399) (106,297)
Hedging settlement 10,442 6,959 22,370 18,928
Other operating revenue 345 413 1,317 1,144
Total revenue 199,124 198,460 797,783 853,906
The main components of total revenue for the three months and year ended December 31, 2024, and December 31, 2023, 
respectively, are detailed below. 
15

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Crude oil sales
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
Three months ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 105,268 62,240 15,313 28,617 211,438
- Quantity sold in bbls 1,901,026 1,085,848 179,754 349,216 3,515,844
- Average price realized USD per bbl 55.37 57.32 85.19 81.95 60.14
Crude oil revenue was in line in Q4 2024 compared to Q4 2023 with slightly lower sales volumes and slightly higher oil prices. 
Malaysia sales are higher in Q4 2024 compared to Q4 023 as a result of two liftings in Q4 2024 versus one lifting in Q4 2023. 
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 2024, WTI averaged USD 70 per bbl compared to USD 79 per bbl for Q4 2023 and the 
average discount to WCS used in IPC’s pricing formula was USD 13 per bbl compared to USD 22 per bbl for Q4 2023.
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 2024 and one cargo lifting in Q4 2023. Produced unsold oil barrels from Bertam at the end of Q4 2024 amounted to 
124,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 75 per bbl for 
Q4 2024 compared to USD 84 per bbl for the comparative period.
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
Year ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 430,231 258,660 101,237 81,093 871,221
- Quantity sold in bbls 7,426,431 4,334,552 1,112,408 989,802 13,863,193
- Average price realized USD per bbl 57.93 59.67 91.01 81.93 62.84
Crude oil revenue was lower by 2% during the year ended December 31, 2024 compared to the year ended December 31, 2023 
mainly due to lower sales volumes partly offset by higher prices. 
16

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
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 WCS price which trades at a discount to WTI. For the year ended December 31, 
2024, WTI averaged USD 76 per bbl compared to USD 78 per bbl for the comparative period and the average discount to WCS 
used in our pricing formula was USD 15 per bbl compared to USD 19 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 81 per bbl for the year ended December 31, 2024 compared to USD 83 per bbl for the comparative period.
Gas and NGL sales
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
Three months ended – December 31, 2023
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 118 14,983 15,101
- Quantity sold in Mcf 77,185 8,585,805 8,662,990
- Average price realized USD per Mcf 1.53 1.75 1.74
Gas and NGL sales revenue was 39% lower for Q4 2024 compared to Q4 2023 mainly due to the lower achieved gas price. IPC’s 
achieved gas price is based on AECO pricing plus a premium. For Q4 2024, IPC realized an average price of CAD 1.61 per Mcf 
compared to AECO average pricing of CAD 1.44 per Mcf. 
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
Year ended – December 31, 2023
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 373 68,137 68,510
- Quantity sold in Mcf 227,032 33,221,660 33,448,692
- Average price realized USD per Mcf 1.64 2.05 2.05
Gas and NGL sales revenue was 49% lower for the year ended December 31, 2024 compared to the year ended December 31, 
2023 mainly due to the lower achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For the year ended December 31, 2024, IPC realized an 
average price of CAD 1.51 per Mcf compared to AECO average pricing of CAD 1.45 per Mcf.
17

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Hedging settlement
IPC enters into risk management contracts in order to ensure a certain level of cash flow. It focuses mainly on oil and gas price 
swaps to limit pricing exposure. Oil and gas pricing contracts are not entered into for speculative purposes. 
The realized hedging settlement for the year ended December 31, 2024 amounted to a gain of USD 22,370 thousand and 
consisted of a gain of USD 21,587 thousand on the oil contracts and a gain of USD 783 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 100,984 thousand for Q4 2024 compared to USD 126,414 
thousand for Q4 2023 and USD 328,110 thousand for the year ended December 31, 2024 compared to USD 491,303 thousand for 
the comparative period, and is analyzed as follows:
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
Three months ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 23,868 38,651 12,091 11,679 (2,921) 83,368
USD/boe2 16.39 14.80 51.74 45.26 n/a 18.28
Cost of blending 37,601 6,872 – – – 44,473
Change in inventory position 638 (873) (1,217) 25 – (1,427)
Production costs 62,107 44,650 10,874 11,704 (2,921) 126,414
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
18

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Year ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 94,817 155,178 50,032 36,288 (14,353) 321,962
USD/boe2 16.33 15.51 35.87 36.27 n/a 17.63
Cost of blending 146,204 26,792 – – – 172,996
Change in inventory position 448 (952) (3,358) 207 – (3,655)
Production costs 241,469 181,018 46,674 36,495 (14,353) 491,303
1  See definition on page 22 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 2023, includes the 
Brooks assets from January 1, 2023.
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 28.89 for Q4 2024 and USD 39.24 for the comparative period and USD 23.27 and USD 25.58 for the year ended 
December 31, 2024, and December 31, 2023, respectively.
Operating costs
Operating costs amounted to USD 79,439 thousand for Q4 2024 compared to USD 83,368 thousand for Q4 2023 and USD 
294,010 thousand for the year ended December 31, 2024 compared to USD 321,962 thousand for the year ended December 31, 
2023. Operating costs per boe amounted to USD 16.96 per boe for 2024 below the guidance and compared with USD 17.63 per 
boe for 2023. 
Cost of blending
For the Suffield area and Onion Lake Thermal assets in Canada, oil production is blended with purchased condensate 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 36,036 thousand for Q4 2024 compared to USD 44,473 thousand for Q4 2023 and USD 
152,735 thousand for the year ended December 31, 2024 compared to USD 172,996 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 2024, IPC had crude entitlement of 124,000 bbl of oil on the FPSO Bertam facility being 
crude produced but not yet sold. 
Depletion and decommissioning costs
The total depletion of oil and gas properties amounted to USD 30,491 thousand for Q4 2024 compared to USD 30,434 thousand 
for Q4 2023 and USD 96,305 thousand for the year ended December 31, 2024 compared to USD 126,010 thousand the year 
ended December 31, 2023 (including an adjustment for accelerated decommissioning activities amounting to USD 24,088 
thousand). 
The depletion charge is analyzed in the following tables:
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
Three months ended – December 31, 2023
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,165 14,654 2,982 3,633 30,434
USD per boe 6.30 5.61 12.76 14.08 6.67
19

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
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
Year ended – December 31, 2023
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands1 37,295 56,897 17,800 14,018 126,010
USD per boe 6.42 5.68 12.76 14.01 6.89
1  In Canada, excludes the adjustment for accelerated decommissioning activities.
2  USD/boe in the tables above is calculated by dividing the depletion cost by the production volume for each country for the period and for 2023, 
includes the Brooks assets from January 1, 2023.
The depletion charge is derived by applying the depletion rate per boe to the volumes produced in the period by each field. The 
depletion rate in Malaysia has significantly increased compared to the prior year following the capitalization of the workover costs 
incurred in Q4 2023 and Q1 2024. 
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 2,430 thousand for Q4 2024 compared to USD 1,309 thousand for Q4 
2023 and USD 8,933 thousand for the year ended December 31, 2024 compared to USD 7,812 thousand for the year ended 
December 31, 2023. This relates to the depreciation of the FPSO Bertam, which is being depreciated to its residual value on a unit 
of production basis to August 2025.
Exploration and business development costs
The total exploration and business developments costs amounted to a cost of USD 2,069 thousand for the year ended December 
31, 2024 and mainly relates to the write-off of exploration costs in Malaysia.
Net financial items
Net financial items amounted to a charge of USD 59,709 thousand for the year ended December 31, 2024, compared to a 
charge of USD 22,736 thousand for the year ended December 31, 2023 and included a net foreign exchange loss of USD 23,427 
thousand for 2024 compared to a net foreign exchange loss of USD 1,911 thousand for the year ended December 31, 2023. The 
foreign exchange movements are mainly resulting from the revaluation of intra-group loan funding balances and the settlement of 
currency hedging.
Excluding foreign exchange movements, the net financial items amounted to a charge of USD 36,282 thousand for the year ended 
December 31, 2024, compared to USD 20,825 thousand for the year ended December 31,2023.  
The interest expense amounted to USD 35,905 thousand for the year ended December 31, 2024, compared to USD 25,635 
thousand for the comparative period in 2023 and mainly related to the bond interest at a coupon rate of 7.25% per annum. The 
increase compared to the comparative period is largely attributable to the additional MUSD 150 bond tap issue completed in Q3 
2023. Interest income generated on cash balances held amounted to USD 17,721 thousand for the year ended December 31, 
2024 and USD 21,774 thousand for the year ended December 31, 2023.
The unwinding of the asset retirement obligation discount rate amounted to USD 14,568 thousand for the year ended December 
31, 2024, compared to USD 13,408 thousand for the year ended December 31, 2023. 
Income tax
The corporate income tax amounted to a charge of USD 33,325 thousand for the year ended December 31, 2024, compared to a 
charge of USD 55,362 thousand for the year ended December 31, 2023. 
The current income tax amounted to a charge of USD 8,313 thousand for the year ended December 31, 2024 and mainly related to 
France and Malaysia. No corporate income tax is expected to be payable in Canada in 2024 due to the usage of historical tax pools. 
20

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

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2024
Capital Expenditure
Development and exploration and evaluation expenditure incurred during the year ended December 31, 2024 was as follows:
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 369,465 42,819 17,035 3,475 432,794
Exploration and evaluation 500 – 1,407 12 1,919
369,965 42,819 18,442 3,487 434,713
Capital expenditure of USD 434,713 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project, drilling 
on the Southern Alberta assets and in Malaysia on the well workovers.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 16,425 thousand as at December 31, 2024, which included USD 14,797 thousand 
in respect of the FPSO Bertam. The FPSO Bertam is being depreciated to its residual value on a unit of production basis to August 
2025.
Financial Position and Liquidity
Financing 
As at January 2023, IPC had MUSD 300 of bonds outstanding, issued in February 2022 and maturing in February 2027 with a fixed 
coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group also had a revolving 
credit facility of MCAD 75 (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In Q3 2023, IPC completed a tap issue of MUSD 150 under IPC’s existing 7.25% bond framework issued at 7% discount to par 
value with proceeds amounting to MUSD 139.5 before transaction costs. For accounting purposes, the discounted amount was 
recognised in the balance sheet and the discount will be unwound over the period to maturity of the bond and charged to the 
interest expense line of the Statement of Operations using the effective interest rate methodology. As at December 31, 2024, IPC 
had a nominal MUSD 450 of bonds outstanding with maturity in February 2027. The bond repayment obligations as at December 
31, 2024, are classified as non-current as there are no mandatory repayments within the next twelve months.
During 2023, the Group increased the Canadian RCF from MCAD 75 to MCAD 180 with a maturity to May 2025. During Q2 
2024, the Group extended the maturity of the Canadian RCF to May 2026. The Canadian RCF is undrawn and fully available as at 
December 31, 2024. During Q3 2024, the Group entered into a letter of credit facility in Canada (the “LC Facility”) to cover existing 
operational letters of credit. As at December 31, 2024, operational letters of credit in an aggregate of MCAD 40.2 have been 
issued under the LC Facility, including letters of credit issued in Q2 2024 for a total amount of MCAD 35 to support the third party 
pipeline construction agreements for the Blackrod project during 2024 and 2025.
As at December 31, 2024, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May 2026. 
IPC makes quarterly repayments of the French Facility and the amount remaining outstanding under the France Facility as at 
December 31, 2024 was MUSD 5.1 million. An amount of MUSD 3.4 drawn under the France Facility as at December 31, 2024 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, 2024. 
Net debt as at December 31, 2024 amounted to MUSD 209. Cash and cash equivalents held amounted to MUSD 247 as at 
December 31, 2024.
IPC intends to fund the remaining Blackrod Phase 1 project development costs with cash on hand and forecast cash flow 
generated by its operations.
Working Capital 
As at December 31, 2024, the Group had a working capital balance including cash of USD 190,771 thousand compared to USD 
487,709 thousand as at December 31, 2023. The difference as at December 31, 2024, from December 31, 2023, is mainly as a 
result of the decreased cash following capital expenditures on the Blackrod Phase 1 development project and the continuing NCIB 
program. 
21

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