===== SIDA 1 ===== Q4 International Petroleum Corporation Audited Consolidated Financial Statements For the years ended December 31, 2023 and 2022 ===== SIDA 2 ===== 2 Contents Report of Management 3 Report of Independent Auditor 4 Consolidated Statement of Operations 9 Consolidated Statement of Comprehensive Income 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, 2023 and 2022, AUDITED ===== SIDA 3 ===== 3 Consolidated Financial Statements For the years ended December 31, 2023 and 2022, 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 (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) 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 Com- mittee, which is comprised solely of independent directors. The Audit Committee reviews the Group’s annual consolidated finan- cial 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 Pricewa- terhouseCoopers SA, Chartered Professional Accountants, Licensed Public Accountants. (Signed) William Lundin (Signed) Christophe Nerguararian Director, President and Chief Executive Officer Chief Financial Officer Vancouver, Canada February 6, 2024 ===== SIDA 4 ===== 4 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, 2023 and 2022 and its financial performance and its cash flows for the years then ended in accordance with IFRS Accounting Standards (IFRS). What we have audited The Corporation’s consolidated financial statements comprise: x the consolidated statements of operations for the years ended December 31, 2023 and 2022; x the consolidated statements of comprehensive in come for the years ended December 31, 2023 and 2022; x the consolidated balance sheet for the years ended December 31, 2023 and 2022; x the consolidated statements of cash flow for the years then ended; x the consolidated statements of changes in equity for the years then ended; and x the notes to the consolidated financial statemen ts, which include significant accounting policies. Basis for opinion We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the consolidated financial statements section of our report. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Independence We are independent of the Corporation in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada. We have fulfilled our other ethical responsibilities in accordance with these requirements. Key audit matter Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the consolidated financial statements for the year ended December 31, 2023. 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. PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch ===== SIDA 5 ===== 5 PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch Key audit matter How our audit addressed the key audit matter The impact of oil and gas reserves on net property, plant and equipment (PP&E) for the Canada, Malaysia, and France segments Refer to note 1 - Corporate information, note 2 - Critical accounting estimates and judgements, and note 8 – Oil and Gas Properties to the consolidated financial statements. The Corporation had USD 1’278.5 million of net PP&E assets as at December 31, 2023. Depletion charges were USD 126.0 million for the year then ended. PP&E is depleted based on the year’s production in relation to the estimated total proved and probable reserves in accordance with the unit of production method. PP&E assets are grouped for recoverability assessment purposes into cash generating units (CGU’s). At each balance sheet date or when there are facts and circumstances that suggest that the net book value of capitalized costs within each field area cost centre 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 there is an indication that an asset may be impaired. Management determines the recoverable amounts of the CGU 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 have been reviewed by Management’s experts, specifically independent qualified reserves evaluators. Significant assumptions developed by management used to determine the recoverable amount of the CGU’s include the proved and probable oil and gas reserves, expected production volumes, future oil and gas prices, future development costs, future production costs and the discount rate. We determined that this is a key audit matter due to (i) the significant judgment made by management, including the use of management’s experts, when developing the expected future cash flows to determine the recoverable amount and the proved and probable oil and gas reserves; and (ii) a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence relating to management’s estimates. Our approach to addressing the matter included the following procedures, among others: භ 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 depletion charges and the recoverable amount of PP&E. As a basis for using this work, management’s experts’ competence, capability and objectivity were evaluated, their work performed was understood and the appropriateness of their work as audit evidence was evaluated by considering the relevance and reasonableness of the assumptions, methods and findings. භ Tested how management determined the recoverable amount of CGU’s, which included the following: o Evaluated the appropriateness of the methods used by management in making these estimates. o Tested the data used in determining these estimates. o Evaluated the reasonableness of significant assumptions used in developing the underlying estimates: ඵ Expected production volumes, future development costs and future production costs by considering the past performance of each segment, and whether these assumptions were consistent with evidence obtained in other areas of the audit. ඵ Future oil and gas prices by comparing those prices with other reputable third- party industry forecasts. ඵ The discount rate, by performing an independent sensitivity analysis. x Recalculated the unit of production rates used to calculate depletion charges of PP&E. ===== SIDA 6 ===== 6 PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch 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, 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 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. ===== SIDA 7 ===== 7 PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch 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: භ Identify and assess the risks of material misstat ement 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. භ 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. භ Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. භ 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. භ 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. භ Obtain sufficient appropriate audit evidence regard ing the financial information of the entities or business activities within the Corporation to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the group audit. We remain solely responsible for our audit opinion. We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. ===== SIDA 8 ===== 8 PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch 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. 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. The engagement partner on the audit resulting in this independent auditor’s report is Colin Johnson. PricewaterhouseCoopers SA Colin Johnson Luc Schulthess Chartered Professional Accountant February 6, 2024 ===== SIDA 9 ===== 9 Consolidated Statement of Operations For the years ended December 31, 2023 and 2022, AUDITED USD Thousands Note 2023 2022 Revenue 3 853,906 1,129,298 Cost of sales Production costs 4 (491,303) (476,986) Depletion and decommissioning costs 8 (101,922) (122,041) Depreciation of other tangible fixed assets 10 (7,812) (10,787) Exploration and business development costs (2,355) (2,775) Gross profit 3 250,514 516,709 Sale of assets 8 19,018 – General, administration and depreciation expenses (18,455) (14,440) Profit before financial items 251,077 502,269 Finance income 5 21,774 6,999 Finance costs 6 (44,510) (44,130) Net financial items (22,736) (37,131) Profit before tax 228,341 465,138 Income tax expense 7 (55,362) (127,413) Net result 172,979 337,725 Net result attributable to: Shareholders of the Parent Company 172,951 337,683 Non-controlling interest 28 42 172,979 337,725 Earnings per share – USD1 17 1.31 2.30 Earnings per share fully diluted – USD1 17 1.28 2.25 1 Based on net result attributable to shareholders of the Parent Company See accompanying notes to the consolidated financial statements ===== SIDA 10 ===== 10 Consolidated Statement of Comprehensive Income For the years ended December 31, 2023 and 2022, AUDITED USD Thousands Note 2023 2022 Net result 172,979 337,725 Other comprehensive income Items that may be reclassified to profit or loss: Reclassification of hedging gains losses to profit or loss 3, 24 (18,928) (19,125) Gains on cash flow hedges 48,786 28,819 Income tax relating to these items (7,051) (2,343) Currency translation adjustments 20,994 (43,461) Items that will not be reclassified to profit or loss: Re-measurements on defined pension plan 21 (679) 3,778 Total comprehensive income 216,101 305,393 Total comprehensive income attributable to: Shareholders of the Parent Company 216,076 305,359 Non-controlling interest 25 34 216,101 305,393 See accompanying notes to the consolidated financial statements ===== SIDA 11 ===== 11 Consolidated Balance Sheet For the years ended December 31, 2023 and 2022, AUDITED USD Thousands Note December 31, 2023 December 31, 2022 ASSETS Non-current assets Oil and gas properties 8 1,278,422 963,375 Other tangible fixed assets 10 25,438 33,374 Right-of-use assets 11 2,814 1,217 Deferred tax assets 7 1,827 1,960 Derivative instruments 23 7,049 – Other assets 12 56,838 41,125 Total non-current assets 1,372,388 1,041,051 Current assets Inventories 13 21,808 15,958 Trade and other receivables 14 113,497 123,609 Derivative instruments 23 35,504 11,741 Current tax receivables 2,714 18 Cash and cash equivalents 15 517,074 487,240 Total current assets 690,597 638,566 TOTAL ASSETS 2,062,985 1,679,617 LIABILITIES Non-current liabilities Financial liabilities 19 5,442 8,711 Bonds 19 435,041 295,440 Lease liabilities 11 2,087 507 Provisions 20 250,657 203,389 Deferred tax liabilities 7 86,348 56,334 Derivative instruments 23 263 – Total non-current liabilities 779,838 564,381 Current liabilities Trade and other payables 22 188,871 118,726 Financial liabilities 19 3,589 3,431 Derivative instruments 23 1,267 1,155 Current tax liabilities 255 17,793 Lease liabilities 11 809 752 Provisions 20 8,097 8,048 Total current liabilities 202,888 149,905 EQUITY Shareholders’ equity 1,080,074 965,140 Non-controlling interest 185 191 Net shareholders’ equity 1,080,259 965,331 TOTAL EQUITY AND LIABILITIES 2,062,985 1,679,617 Approved by the Board of Directors (Signed) C. Ashley Heppenstall (Signed) William Lundin Director Director See accompanying notes to the consolidated financial statements ===== SIDA 12 ===== 12 Consolidated Statement of Cash Flow For the years ended December 31, 2023 and 2022, AUDITED USD Thousands Note 2023 2022 Cash flow from operating activities Net result 172,979 337,725 Adjustments for non-cash related items: Depletion, depreciation and amortization 8,10,11 111,303 134,436 Gain on sale of assets (19,018) – Income tax 7 55,362 127,413 Amortization of capitalized financing fees 6 342 2,228 Amortization of capitalized bonds fees 6 1,263 1,024 Foreign currency exchange 6 1,911 7,872 Interest expense 6 25,635 20,689 Interest income 5 (21,774) (6,966) Unwinding of asset retirement obligation discount 6 13,408 10,758 Change in pension liability 21 446 542 Share-based costs 18 11,690 7,997 Other 2,998 1,209 Cash flow generated from operations (before working capital adjustments and income taxes) 356,545 644,927 Changes in working capital 36,058 (13,305) Decommissioning costs paid 20 (8,118) (5,809) Other payments 20 (2,370) (2,736) Income taxes received paid (34,868) (16,470) Interest received 20,884 6,656 Interest paid (21,977) (11,445) Net cash flow from operating activities 346,154 601,818 Cash flow used in investing activities Investment in oil and gas properties 8 (312,729) (157,662) Acquisition of Cor4 net of cash acquired 9 (59,419) – Disposal of assets 9 20,191 – Investment in other fixed assets 10 (510) (151) Net cash (outflow) from investing activities (352,467) (157,813) Cash flow from financing activities Borrowings / (Repayments) 19 (3,111) (100,979) Bonds issuance 137,550 300,000 Paid financing fees (507) (5,583) Financing of Substantial Issuer Bid (“SIB”) 16 – (100,957) Repurchase of own shares (“NCIB”) 16 (95,358) (80,578) Other payments (980) (793) Dividend paid (31) – Net cash (outflow) from financing activities 37,563 11,110 Change in cash and cash equivalents 31,250 455,115 Cash and cash equivalents at the beginning of the period 487,240 18,810 Currency exchange difference in cash and cash equivalents (1,416) 13,315 Cash and cash equivalents at the end of the period 517,074 487,240 See accompanying notes to the consolidated financial statements ===== SIDA 13 ===== 13 Consolidated Statement of Changes in Equity For the years ended December 31, 2023 and 2022, 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, 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) Acquisition of Cor41 – – – – 881 – 881 – 881 Cash flow hedge – – – – 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 shares2 (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 230,005 808,846 (10,745) 18,838 31,344 1,786 1,080,074 185 1,080,259 1 See Note 9 2 See Note 16 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 January 31, 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 share premium. 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, 2022 528,764 298,212 11,291 9,700 874 (1,455) 847,386 157 847,543 Net result – 337,683 – – – – 337,683 42 337,725 Re-measurements on defined pension plan – – – – – 3,778 3,778 – 3,778 Cash flow hedge – – – – 7,351 – 7,351 – 7,351 Currency translation difference – – (42,583) (791) (267) 188 (43,453) (8) (43,461) Total comprehensive income – 337,683 (42,583) (791) 7,084 3,966 305,359 34 305,393 Repurchase of own shares1 (80,578) – – – – – (80,578) – (80,578) Substantial Issuer Bid (“SIB”)1 (100,957) – – – – – (100,957) – (100,957) Share based payments 2 (8,510) – – 2,440 – – (6,070) – (6,070) Balance at December 31, 2022 338,719 635,895 (31,292) 11,349 7,958 2,511 965,140 191 965,331 1 See Note 16 2 The second instalment of IPC RSP 2020 awards and the first instalment of IPC RSP 2021 awards vested on February 28, 2022, at a price of CAD 8.93 per award. The difference between the value at vesting date and at grant (respectively CAD 4.35 per award and CAD 4.07 per award) was offset against share premium. The third instalment of IPC RSP 2019 awards and the IPC PSP 2019 awards vested on June 30, 2022, at a price of CAD 12.83 per award. The difference between the value at vesting date and at grant (respectively CAD 5.84 per award and CAD 4.28 per award) was offset against share premium. See also Note 18. See accompanying notes to the consolidated financial statements ===== SIDA 14 ===== 14 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED 1. CORPORATE INFORMATION 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 2000, 885 West Georgia Street, Vancouver, BC V6C 3E8, 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 (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). 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. Certain comparative figures have been reclassified to conform with the financial statements presentation in the current year. These consolidated financial statements have been approved by the Board of Directors of IPC and authorized for issuance on February 6, 2024. C. Going concern The Group’s consolidated financial statements for the year ended December 31, 2023, 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. D. Changes in accounting policies and disclosures During the year ended December 31, 2023, the Group applied the amended accounting standards, interpretations and annual improvement points that are effective as of January 1, 2023. 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 will have a material impact on the consolidated financial statements. E. 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. F. Joint Arrangements Oil and gas operations of the Group are conducted as co-licencees 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. ===== SIDA 15 ===== 15 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED G. 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, 2023 December 31, 2022 Average Period end Average Period end 1 EUR equals USD 1.0816 1.1050 1.0539 1.0666 1 USD equals CAD 1.3496 1.3251 1.3015 1.3538 1 USD equals MYR 4.5598 4.5950 4.3995 4.4050 H. 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. I. 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. 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, these exploration costs are charged to the income statement. 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. Routine maintenance and repair costs for producing assets are expensed to the income statement when they occur. Property, plant and equipment 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 income statement 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 income statement. In the event of a sale in the exploration stage, any deficit is included in the income statement. ===== SIDA 16 ===== 16 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED Impairment tests are performed annually or when there are indicators of impairment that suggest that the net book value of capitalized costs within each field area cost center less any provision for asset retirement obligation costs is higher than the anticipated future net cash flow from oil and gas reserves attributable to the Corporation’s interest in the related field areas. Capitalized costs cannot be carried unless those costs can be supported by future cash flows from that asset. Provision is made for any impairment, where the net carrying value, according to the above, exceeds the recoverable amount, which is the higher of value in use and fair value less costs of disposal, determined through estimated future discounted net cash flows using prices and cost levels used by management in their internal forecasting. 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. J. 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 on a unit of production basis using the Bertam field 2P reserves to August 2025 being the original Bertam field production sharing contract (“PSC“) expiry date, before the PSC extension to 2035. 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 income statement 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. K. 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. 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. L. Impairment of Assets At each balance sheet date or 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 there is an indication that an asset may be impaired. Management determined 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 have been reviewed by Management’s experts, specifically independent qualified reserves auditor. The recoverable amount is the higher of fair value less costs of disposal and value in use. In determining fair value less costs of disposal, recent market transactions are considered, if available. In the absence of such transactions, an appropriate valuation model is used. Value in use is calculated by discounting estimated future cash flows 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 income statement. If indications exist that previously recognized impairment losses no longer exist or are decreased, the recoverable amount is estimated. 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, ===== SIDA 17 ===== 17 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED 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. An impairment loss is the amount by which the carrying amount of the individual asset or CGU exceeds its recoverable amount. M. 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 23. N. 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 23. 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 finance income or costs. 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 profit or loss. When a forecasted transaction is no longer expected to occur, the cumulative gain or loss that was reported in equity is immediately recognized in profit or loss. ===== SIDA 18 ===== 18 O. 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 income statement as revenue. P . Cash and cash equivalents Cash and cash equivalents include cash at bank and cash in hand. Q. 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. R. 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 and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. 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 income statement 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. S. 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. Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 19 ===== 19 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 income statement 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 income statement over the vesting period without revaluation of the value of the option. T. Taxation The components of tax are current and deferred. Tax is recognized in the income statement, 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. U. 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. V. 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 cash-generating units (“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, 2023 and 2022, AUDITED ===== SIDA 20 ===== 20 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. 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 in 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. An independent qualified reserves auditor 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. Impairment of oil and gas properties Key assumptions in the impairment models relate to prices and costs that are based on forward curves and the long-term corporate assumptions. Annual impairment tests are performed in conjunction with the annual reserves certification process. 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 proved and probable oil and gas reserves, expected production volumes, future oil and gas prices, future development costs, future production costs 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, 2023 and 2022, AUDITED ===== SIDA 21 ===== 21 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. 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 2022 USD Thousands Canada Malaysia France Other Total Crude oil 778,365 184,143 112,379 – 1,074,887 NGLs 774 – – – 774 Gas 154,754 – – – 154,754 Net sales of oil and gas 933,893 184,143 112,379 – 1,230,415 Change in under/over lift position – – (8,553) – (8,553) Royalties (105,856) – (6,660) – (112,516) Hedging settlement 19,125 – – – 19,125 Other operating revenue 111 – 716 – 827 Revenue 847,273 184,143 97,882 – 1,129,298 Operating costs (217,017) (35,051) (35,588) – (287,656) Cost of blending (189,172) – – – (189,172) Change in inventory position 1,038 (1,916) 720 – (158) Depletion and decommissioning costs (75,077) (34,687) (12,277) – (122,041) Depreciation of other tangible fixed assets – (10,787) – – (10,787) Exploration and business development costs 97 – – (2,872) (2,775) Gross profit/(loss) 367,142 101,702 50,737 (2,872) 516,709 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 22 ===== 22 USD Thousands Assets Liabilities 2023 2022 2023 2022 Malaysia 175,816 251,059 48,743 34,573 France 204,006 209,088 95,840 120,095 Canada 1,966,370 1,246,105 1,082,035 560,709 Other 198,520 300,276 237,835 325,820 Intercompany balance elimination (481,727) (326,911) (481,727) (326,911) Total Assets / Liabilities 2,062,985 1,679,617 982,726 714,286 Shareholders’ equity N/A N/A 1,080,074 965,140 Non-controlling interest N/A N/A 185 191 Total equity for the group N/A N/A 1,080,259 965,331 Total consolidated 2,062,985 1,679,617 2,062,985 1,679,617 4. PRODUCTION COSTS USD Thousands 2023 2022 Cost of operations 275,868 245,360 Tariff and transportation expenses 40,929 36,873 Direct production taxes 5,165 5,423 Operating costs 321,962 287,656 Cost of blending1 172,996 189,172 Change in inventory position (3,655) 158 Total production costs 491,303 476,986 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 2023 2022 Interest income 21,774 6,966 Other financial income – 33 Total finance income 21,774 6,999 6. FINANCE COSTS USD Thousands 2023 2022 Foreign exchange loss, net 1,911 7,872 Interest expense 25,635 20,689 Unwinding of asset retirement obligation discount 13,408 10,758 Amortization of loan fees 342 2,228 Amortization of bond fees 1,263 1,024 Loan commitment fees 672 537 Other financial costs 1,279 1,022 Total finance costs 44,510 44,130 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 23 ===== 23 7. INCOME TAX USD Thousands 2023 2022 Current tax (14,457) (29,365) Deferred tax (40,905) (98,048) Total tax expense (55,362) (127,413) In 2022, the current tax includes a windfall profits tax on energy companies applicable to the Group in France amounting to USD 10,915 thousand. The Group is within the scope of the OECD Pillar Two model rules. Pillar Two legislation is enacted or expected to be enacted in all relevant Group entities in 2024, and will come into effect from January 1, 2024. Since the Pillar Two legislation was not effective at the reporting date, the Group has no related current tax exposure. 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 Group is in the process of assessing its exposure to the Pillar Two legislation for when it comes into effect. All relevant entities within the Group have an effective tax rate that exceeds 15% and as such the expected impact should be insignificant. 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 2023 2022 Profit before tax 228,341 465,138 Tax calculated at the corporate tax rate in Canada 25% (57,086) (116,284) Effect of foreign and domestic tax rates 7,470 4,210 Tax effect of recognition / (derecognition) of unrecorded tax losses (4,736) (5,134) Tax effect due to true-up of provision to prior year tax filings (102) 531 France Solidarity Contribution (windfall tax) – (10,915) Other (908) 179 Total tax (55,362) (127,413) Specification of deferred tax assets and tax liabilities1 USD Thousands 2023 2022 Unused tax loss carry forward 34,446 32,815 Other 5,959 5,841 Deferred tax assets 40,405 38,656 Accelerated allowances 115,399 90,400 Derivative hedges 9,527 2,630 Deferred tax liabilities 124,926 93,030 Deferred taxes, net (84,521) (54,374) 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, 2023 and 2022, AUDITED ===== SIDA 24 ===== 24 8. OIL AND GAS PROPERTIES USD Thousands 2023 2022 Exploration and Evaluation Assets – 4,764 Property, Plant and Equipment 1,278,422 958,611 Oil and gas properties 1,278,422 963,375 Exploration and Evaluation Assets 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 – – – – USD Thousands Canada Malaysia France Total Cost January 1, 2022 12,751 181 5,105 18,037 Additions1 (802) 149 4 (649) Reclassification (11,974) (330) – (12,304) Currency translation adjustments 25 – (345) (320) Net book value December 31, 2022 – – 4,764 4,764 1 Net revenues on appraisal projects were being offset against capitalized costs of Exploration and Evaluation Assets. Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 25 ===== 25 Property, Plant and Equipment USD Thousands Canada Malaysia France Total Cost January 1, 2023 1,089,789 566,606 399,237 2,055,632 Acquisition of Cor4 - See Note 9 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 period (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 for gross proceeds of CAD 28.1 million (USD 20.8 million) and a net accounting gain on disposal of CAD 25.7 million (USD 19.0 million). 2 In Canada, includes an adjustment in the first quarter of 2023 for accelerated decommissioning activities funded by a non-cash site rehabilitation program. USD Thousands Canada Malaysia France Total Cost January 1, 2022 1,021,944 534,443 408,211 1,964,598 Additions 118,762 27,305 12,244 158,311 Change in estimates 5,231 4,528 2,182 11,941 Reclassification 11,974 330 – 12,304 Currency translation adjustments (68,122) – (23,400) (91,522) December 31, 2022 1,089,789 566,606 399,237 2,055,632 Accumulated depletion January 1, 2022 (267,585) (450,347) (293,132) (1,011,064) Depletion charge for the period (75,077) (34,687) (12,277) (122,041) Currency translation adjustments 19,389 – 16,695 36,084 December 31, 2022 (323,273) (485,034) (288,714) (1,097,021) Net book value December 31, 2022 766,516 81,572 110,523 958,611 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 26 ===== 26 Impairment test The Group carried out its impairment testing at December 31, 2023, on a CGU basis in conjunction with the annual reserves audit process. The Group used appropriate oil or natural gas price curves based on forward forecasts as at December 31, 2023, a future cost inflation factor of 2% (2022: 2%) per annum, production and cost profiles based on proved and probable reserves (2P reserves) as at December 31, 2023 and a discount rate of 10% (10% at December 31, 2022) to calculate the estimated future post-tax cash flows. The following prices were used in the impairment testing as at December 31, 2023: Price Decks 2024 2025 2026 2027 2028 Average annual increase thereafter Dated Brent (USD/bbl) 80.00 80.00 80.00 81.60 83.23 2% West Texas Intermediate (USD/bbl) 76.00 76.00 76.00 77.52 79.07 2% Western Canadian Select (USD/bbl) 61.00 63.50 63.25 64.52 65.81 2% AECO Gas (CAD/mcf) 2.33 3.64 3.95 4.03 4.11 2% In 2023, as a result of the testing, no impairment of the oil and gas properties was required. Sensitivities were calculated on the valuation of the estimated future post-tax cash flows. Using a discount rate of 12% instead of 10% or a USD 5/bbl decrease in the oil price curve or using a flat gas price curve at CAD 3.50/mcf did not result in an impairment charge. 9. COR4 ACQUISITION 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 amalgamated 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 Settled by: Cash payment 62,211 The Corporation performed a preliminary purchase price allocation for the Cor4 acquisition. The amounts disclosed above were determined provisionally pending the finalization of the valuation for those assets and liabilities. Up to twelve months from the effective date of the Cor4 acquisition, further adjustments may be made to the fair values assigned to the identifiable assets acquired and liabilities assumed. Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 27 ===== 27 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%. 10. OTHER TANGIBLE FIXED ASSETS 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 period (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 USD Thousands FPSO Other Total Cost January 1, 2022 206,173 10,163 216,336 Additions – 151 151 Disposals – (44) (44) Currency translation adjustments (1,320) (491) (1,811) December 31, 2022 204,853 9,779 214,632 Accumulated depreciation January 1, 2022 (162,524) (7,449) (169,973) Depreciation charge for the period (10,787) (891) (11,678) Disposals – 36 36 Currency translation adjustments – 357 357 December 31, 2022 (173,311) (7,947) (181,258) Net book value December 31, 2022 31,542 1,832 33,374 The FPSO located on the Bertam field, Malaysia, is being depreciated on a unit of production basis using the Bertam field 2P reserves to August 2025, being the original Bertam field PSC expiry date, before the PSC extension to 2035. 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. Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 28 ===== 28 11. RIGHT-OF-USE ASSETS AND LEASE LIABILITIES USD Thousands Buildings 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 USD Thousands Buildings January 1, 2022 1,639 Additions 393 Disposal (66) Depreciation (717) Currency translation adjustments (32) Right-of-use-assets as at December 31, 2022 1,217 Current 752 Non-Current 507 Lease Liabilities as at December 31, 2022 1,259 12. OTHER NON-CURRENT ASSETS USD Thousands December 31, 2023 December 31, 2022 Financial assets 41,486 35,882 Intangible assets 15,352 5,243 56,838 41,125 Financial assets mainly represent cash payments made to an asset retirement obligation fund for the Bertam field, Malaysia for an amount of USD 28.7 million (2022: USD 28.2 million). In 2023, an amount of USD 1.8 million (2022: USD 1.9 million) was paid into the asset retirement obligation fund which is held in local currency. (Also see Note 20.) Financial assets also include secured amounts of USD 7.7 million towards the future asset retirement obligation for the Bertam field and cash-collaterized guarantees placed in 2023 in respect of work commitments in Malaysia amounting to USD 4.5 million. Intangible assets mainly represent carbon offsets purchased in Canada. An amount of USD 9.4 million (CAD 12.5 million) carbon offsets has been purchased in 2023. 13. INVENTORIES USD Thousands December 31, 2023 December 31, 2022 Hydrocarbon stocks 13,530 8,988 Well supplies and operational spares 8,278 6,970 21,808 15,958 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 29 ===== 29 14. TRADE AND OTHER RECEIVABLES USD Thousands December 31, 2023 December 31, 2022 Trade receivables 97,264 112,696 Underlift 1,029 599 Joint operations debtors 910 982 Prepaid expenses and accrued income 10,986 6,585 Other 3,308 2,747 113,497 123,609 15. CASH AND CASH EQUIVALENTS Cash and cash equivalents include only cash at hand or held in bank accounts. 16. SHARE CAPITAL The Corporation’s issued common share capital is as follows: Number of shares Balance at January 1, 2022 155,198,105 Cancellation of repurchased common shares (10,112,042) Cancellation following the Substantial Issuer Bid (8,258,064) Balance at December 31, 2022 136,827,999 Cancellation of repurchased common shares (NCIB) (9,835,933) Balance at December 31, 2023 126,992,066 The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. As at January 1, 2022, IPC had a total of 155,198,105 common shares issued and outstanding, of which IPC held 1,160,651 common shares in treasury. All common shares held in treasury as at January 1, 2022 were cancelled during January 2022. During 2022, under the normal course issuer bid/share repurchase program announced in December 2021 and renewed in December 2022 (NCIB), IPC purchased and cancelled an aggregate of 8,951,391 common shares. During Q2 2022, IPC commenced an offer to repurchase common shares under the substantial issuer bid (SIB). Under the SIB, IPC purchased and cancelled an aggregate of 8,258,064 common shares. As at December 31, 2022, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in treasury. Over the period of December 5, 2022 to December 4, 2023, IPC purchased and cancelled a total of 9,333,479 common shares under the NCIB (8,603,179 common shares purchased and cancelled in 2023). The NCIB was further renewed in Q4 2023 and IPC is entitled to purchase up to 8,342,119 common shares over the period of December 5, 2023 to December 4, 2024. During December 2023, IPC purchased and cancelled a total of 1,232,754 common shares under the renewed NCIB. 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. 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, do not carry the right to vote on matters to be decided by the holders of IPC’s common shares and do not impact the earnings per share calculations. Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED ===== SIDA 30 ===== 30 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED 17. 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 periods presented. 2023 2022 Net result attributable to shareholders of the Parent Company, USD 172,951,130 337,682,813 Weighted average number of shares for the period 132,080,662 146,662,032 Earnings per share, USD 1.31 2.30 Weighted average diluted number of shares for the period 135,349,211 149,976,365 Earnings per share fully diluted, USD 1.28 2.25 18. 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”) 2020 awards vested on February 1, 2023 at a price of CAD 14.26 per award. The IPC PSP 2021 awards are subject to continued employment and to certain performance conditions being met. The total outstanding number of awards at December 31, 2023, is 1,716,000 which vest on February 1, 2024. Each award was fair valued at the grant date at CAD 3.61 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 0.45%, expected volatility of 68%, dividend yield rate of 0%, and an exercise price of CAD zero. 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, 2023, is 937,000 which vest on February 1, 2025. 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, 2023, 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. IPC Performance Share Plan 2020 Awards 2021 Awards 2022 Awards 2023 Awards Total Outstanding at January 1, 2023 1,017,105 1,716,000 937,000 – 3,670,105 Awarded during the period – – – 813,000 813,000 Forfeited during the period – – – – – Vested during the period (1,017,105) – – – (1,017,105) Outstanding at December 31, 2023 – 1,716,000 937,000 813,000 3,466,000 Vesting date February 1, 2024 – 1,716,000 – – 1,716,000 February 1, 2025 – – 937,000 – 937,000 February 1, 2026 – – – 813,00 813,000 Outstanding at December 31, 2023 – 1,716,000 937,000 813,000 3,466,000 The last third of the IPC Restricted Share Plan (“RSP”) 2020 awards vested on February 1, 2023, at a price of CAD 14.26 per award. ===== SIDA 31 ===== 31 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED The second third of the IPC RSP 2021 awards vested on February 1, 2023, at a price of CAD 14.26 per award. The total outstanding number of 2021 awards under the IPC RSP as at December 31, 2023, is 321,512 which vest on February 1, 2024, subject to continued employment. Each award was fair valued at the grant date at CAD 4.07. The first third of the IPC RSP 2022 awards vested on February 1, 2023, at a price of CAD 14.26 per award. The total outstanding number of 2021 awards under the IPC RSP as at December 31, 2023, is 307,359 which vest over two years on each of February 1, 2024 and February 1, 2025, subject to continued employment. Each award was fair valued at the grant date at CAD 9.09. The total outstanding number of IPC RSP 2023 awards as at December 31, 2023, is 330,708 which vest over three years as to one-third on each of February 1, 2024, February 1, 2025, and February 1, 2026, subject to continued employment. Each award was fair valued at the grant date at CAD 14.27. IPC Restricted Share Plan 2020 Awards 2021 Awards 2022 Awards 2023 Awards Total Outstanding at January 1, 2023 199,304 674,225 484,534 – 1,358,063 Awarded during the period – – – 330,708 330,708 Forfeited during the period (792) (17,044) (16,294) – (34,130) Vested during the period (198,512) (335,669) (160,881) – (695,062) Outstanding at December 31, 2023 – 321,512 307,359 330,708 959,579 Vesting date February 1, 2024 – 321,512 153,679 110,236 585,427 February 1, 2025 – – 153,680 110,236 263,916 February 1, 2026 – – – 110,236 110,236 Outstanding at December 31, 2023 – 321,512 307,359 330,708 959,579 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, 2023 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, 2023 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, 2023 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 total outstanding RSP awards outstanding as at December 31, 2023, is 14,483. In 2023, 10,703 awards issued in 2019, 46,551 awards issued in 2020, 18,277 awards issued in 2021, and 3,096 awards issued in 2022 have been exercised at a price of CAD 12.94. The costs charged to the statement of operations of the Group for the Share-Based payments are summarized in the following table: USD Thousands 2023 2022 IPC PSP – 2019 Awards – 488 IPC RSP – 2019 Awards – 90 IPC PSP – 2020 Awards 159 984 IPC RSP – 2020 Awards 35 252 IPC PSP – 2021 Awards 1,881 1,712 IPC RSP – 2021 Awards 377 981 IPC PSP – 2022 Awards 2,856 1,721 IPC RSP – 2022 Awards 1,063 1,769 IPC PSP – 2023 Awards 3,360 – IPC RSP – 2023 Awards 1,959 – 11,690 7,997 ===== SIDA 32 ===== 32 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED 19. FINANCIAL LIABILITIES USD Thousands December 31, 2023 December 31, 2022 Bank loans 9,031 12,142 Bonds 440,288 300,000 Capitalized financing fees (5,247) (4,560) 444,072 307,582 As at January 2022, the Group had a reserve-based lending (RBL) credit facility of USD 140 million in connection with its oil and gas assets in France and Malaysia and a RBL credit facility of CAD 300 million in connection with its oil and gas assets in Canada. In February 2022, IPC completed the issuance of USD 300 million of bonds, which mature in February 2027 and have a fixed coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group used a portion of the proceeds of the bonds to fully repay the outstanding RBL credit facilities, which were then cancelled. At the same time, the Group entered into 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, 2023, IPC had a nominal USD 450 million of bonds outstanding with maturity in February 2027. In Q1 2023, the Group increased the Canadian RCF to CAD 150 million and extended the maturity to May 2025. In Q3 2023, the Group further increased the Canadian RCF to CAD 165 million and in Q4 2023, the Group further increased the Canadian RCF to CAD 180 million. No cash amounts were drawn under the Canadian RCF as at December 31, 2023. The bond repayment obligations as at December 31, 2023, are classified as non-current as there are no mandatory repayments within the next twelve months. As at December 31, 2023, IPC had a EUR 13 million unsecured credit facility in France (the “France Facility“), with maturity in May 2026. IPC commenced quarterly repayments of the French Facility in August 2022. The amount remaining outstanding under the France Facility as at December 31, 2023 was USD 9 million (EUR 8 million). An amount of USD 3.6 million (EUR 3.2 million) drawn under the France Facility as at December 31, 2023 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, 2023. The net cash reconciliation can be summarized as follows: USD Thousands December 31, 2023 December 31, 2022 Cash and cash equivalents 517,074 487,240 Bonds (440,288) (300,000) Borrowings (9,031) (12,142) Lease liabilities (2,896) (1,259) Net cash 64,859 173,839 ===== SIDA 33 ===== 33 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, 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, 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 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, 2022 18,810 (1,664) (1,806) (111,315) – (95,975) Cash flows 455,115 793 – 100,979 (300,000) 256,887 Reclassification Long term / Short term – – (1,625) 1,625 – – Additional leases – (393) – – – (393) Currency translation adjustments 13,315 5 – – – 13,320 Net (debt)/cash as at December 31, 2022 487,240 (1,259) (3,431) (8,711) (300,000) 173,839 Net cash (excluding lease liabilities) 175,098 20. PROVISIONS 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 Disposals 1 (2,483) – – – (2,483) Changes in estimates 9,973 – 679 – 10,652 Payments (8,118) (1,081) (925) (364) (10,488) Other 2 (1,272) – – – (1,272) Reclassification 3 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 for gross proceeds of CAD 28.1 million (USD 20.8 million) and a net accounting gain on disposal of CAD 25.7 million (USD 19.0 million). 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 12). ===== SIDA 34 ===== 34 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED USD Thousands Asset retirement obligation Farm-in obligation Pension obligation Other Total January 1, 2022 196,362 4,199 4,448 1,357 206,366 Additions – – 542 1,034 1,576 Unwinding of asset retirement obligation discount 10,758 – – – 10,758 Changes in estimates 11,375 567 (3,778) – 8,164 Payments (5,809) (1,153) (718) (865) (8,545) Reclassification 1 1,909 – – – 1,909 Currency translation adjustments (8,346) (209) (188) (48) (8,791) December 31, 2022 206,249 3,404 306 1,478 211,437 Non-current 199,335 2,270 306 1,478 203,389 Current 6,914 1,134 – – 8,048 Total 206,249 3,404 306 1,478 211,437 1 The reclassification of the asset retirement obligation related to the 2022 payment to the asset retirement obligation fund in respect of the Bertam asset, Malaysia (see Note 12). 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% (2022: 6%) per annum was used, based on a credit risk adjusted rate. 21. 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, 2023 December 31, 2022 Present value of defined benefit obligation 22,241 13,910 Fair value of plan assets (21,690) (13,604) Pension obligation, ending balance 551 306 The movement in the defined benefit obligation over the year is as follows: USD Thousands For the year ended December 31, 2023 For the year ended December 31, 2022 Opening balance 13,910 14,714 Current service cost 423 596 Ordinary contributions paid by employees 617 479 Additional contributions paid by employees 6,685 2,291 Interest expense on defined benefit obligation 322 28 Actuarial (gain)/loss on defined benefit obligation 524 (3,706) Administration costs 16 13 Benefits paid from plan assets (2,135) (232) Past service cost – (75) Foreign exchange (gain)/loss 1,879 (198) Defined benefit obligation, ending balance 22,241 13,910 The weighted average duration of the defined benefit obligation is 15.2 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. ===== SIDA 35 ===== 35 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED The movement in the fair value of the plan assets over the year is as follows: USD Thousands For the year ended December 31, 2023 For the year ended December 31, 2022 Opening balance 13,604 10,266 Ordinary contributions paid by employer 925 718 Ordinary contributions paid by employees 617 479 Additional contributions paid by employees 6,685 2,291 Interest income on plan assets 315 20 Return on plan assets excluding interest income (155) 71 Foreign exchange gain/(loss) 1,834 (9) Benefits paid from plan assets (2,135) (232) Fair value of plan assets, ending balance 21,690 13,604 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 income statement associated with the Group’s pension plan is as follows: USD Thousands For the year ended December 31, 2023 For the year ended December 31, 2022 Current service cost 423 596 Interest expense on defined benefit obligation 322 28 Administration costs 16 13 Past service cost – (75) Interest income on plan assets (315) (20) Total expense recognized 446 542 The expense associated with the Group’s pension plan of USD 446 thousand was included within general and administrative expenses. The Group also recognized in other comprehensive income a USD 679 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, 2023 For the year ended December 31, 2022 Discount rate 1.90% 2.25% Inflation rate 1.25% 1.25% Future salary increase 1.25% 1.25% Future pension increases 0.00% 0.00% Retirement ages, male (‘M’) and female (‘F’) M65/F64 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 6.9% Increase by 7.8% Salary growth rate 0.50% Increase by 0.2% Decrease by 0.3% Life Expectancy One year Increase by 1.1% Decrease by 1.1% 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, 2023 and 2022, AUDITED 22. TRADE AND OTHER PAYABLES USD Thousands December 31, 2023 December 31, 2022 Trade payables 42,761 20,547 Joint operations creditors 22,257 14,348 Accrued expenses 118,912 78,206 Other 4,941 5,625 188,871 118,726 23. 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, 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 12 2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments. 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 December 31, 2022 USD Thousands Total Financial assets at amortized cost Fair value recognized in profit or loss (FVTPL) Derivatives used for hedging Other assets1 35,882 35,882 – – Derivative instruments 11,741 – – 11,741 Joint operation debtors 982 982 – – Other current receivables2 116,060 115,461 599 – Cash and cash equivalents 487,240 487,240 – – Financial assets 651,905 639,565 599 11,741 1 See Note 12 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, 2023 and 2022, AUDITED December 31, 2022 USD Thousands Total Financial liabilities at amortized cost Fair value recognized in profit or loss (FVTPL) Derivatives used for hedging Non-current financial liabilities 304,151 304,151 – – Current financial liabilities 3,431 3,431 – – Derivative instruments 1,155 – – 1,155 Joint operation creditors 14,348 14,348 – – Other current liabilities 122,171 122,171 – – Financial liabilities 445,256 444,101 – 1,155 The carrying amount of the Group’s financial assets 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, 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 December 31, 2022 USD Thousands Level 1 Level 2 Level 3 Other current receivables 599 – – Derivative instruments – current – 11,741 – Financial assets 599 11,741 – Derivative instruments – current – 1,155 – Financial liabilities – 1,155 – 24. 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, 2023, 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, 2023, the trade receivables amounted to USD 97,264 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, 2023 and 2022, 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 19). 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, 2023 December 31, 2022 Non-current Repayment within 1- 5 years: - Bank loans 5,442 8,711 - Bonds1 440,288 300,000 445,730 308,711 Current Repayment within 12 months: - Bank loans 3,589 3,431 Repayment within 6 months: - Trade payables 42,761 20,547 - Joint operation creditors 22,257 14,348 - Other current liabilities 4,941 5,625 - Current tax liabilities 255 17,793 73,803 61,744 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. In 2023, IPC entered into foreign currency hedges in Canada to buy CAD 20 million per month at CAD 1.36 (sell USD) and in Malaysia to buy MYR 11.5 million per month at MYR 4.63 (sell USD) in respect of 2024, and to buy CAD 15 million per month at CAD 1.36 (sell USD) in respect of 2025, to partially meet forecast operational expenses in those countries. In respect of the forecast Blackrod development capital expenditure in Canada, IPC entered into further currency hedges to purchase a total CAD 556 million for the period January 2024 to December 2025 at an average rate of CAD 1.33 (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, 2023 and 2022, AUDITED The outstanding derivative instruments can be specified as follows: Fair value of outstanding derivative instruments in the balance sheet USD Thousands December 31, 2023 December 31, 2022 Assets Liabilities Assets Liabilities Currency hedge - CAD 13,644 1,328 1,084 – Currency hedge - MYR 618 – 2,886 – Total 14,262 1,328 3,970 – Non-current 7,049 61 – – Current 7,213 1,267 3,970 – Total 14,262 1,328 3,970 – The following tables summarize the effects that changes in currencies against the US Dollar would have on operating result and equity 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, 2023 and 2022. 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 Shift of currency exchange rates USD Thousands Average rate 2022 USD weakening 10% USD strengthening 10% Gross profit in the financial statements 516,709 516,709 EUR/USD 0.9489 0.8626 1.0437 CAD/USD 1.3015 1.1832 1.4317 Total effect on gross profit (41,704) 41,704 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, 2023 and 2022, AUDITED The Group had oil price sale financial hedges outstanding as at December 31, 2023, which are summarized as follows: Period Volume (barrels per day) Type Average Pricing January 1, 2024 – December 31, 2024 17,700 WTI/WCS Differential USD -15.03/bbl January 1, 2024 – December 31, 2024 6,250 WTI Sale Swap USD 80.94/bbl The Group had condensate financial hedges outstanding as at December 31, 2023, which are summarized as follows: Period Volume (barrels per day) Type Average Pricing January 1, 2024 – March 31, 2024 3,000 C5/WTI Differential USD -1.60/bbl The Group had no gas price sale financial hedges outstanding as at December 31, 2023. The Group had electricity financial hedges outstanding as at December 31, 2023, 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, 2023 December 31, 2022 Assets Liabilities Assets Liabilities Oil price hedge 28,291 – 1,155 Gas price hedge – – 7,771 – Electricity price hedge – 202 – – Total 28,291 202 7,771 1,155 Non-current – 202 – – Current 28,291 – 7,771 1,155 Total 28,291 202 7,771 1,155 In addition to the outstanding derivative instruments in the balance sheet disclosed above, a gain of USD 18,928 thousand (2022: USD 19,125 thousand) was recognised in the statement of operations in relation to settled oil and gas derivatives. The table below summarizes the effect that a change in the oil and gas price would have had on the net result and equity at December 31, 2023 and 2022: 2023 net result (USD Thousands) 172,979 172,979 Possible shift (%) (10%) 10% Total effect on net result (USD Thousands) (60,010) 60,010 2022 net result (USD Thousands) 337,725 337,725 Possible shift (%) (10%) 10% Total effect on net result (USD Thousands) (91,032) 91,032 ===== SIDA 41 ===== 41 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED 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, 2023, the Group’s long-term debt is mainly comprised of a fixed coupon rate of 7.25%. As such, changes in interest rate will not have a significant adverse impact on interest expense. 25. 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, 2023 or in the comparative periods. 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. 26. 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 2023 2022 Salaries, bonuses and other short-term benefits 57,280 45,073 Security social costs 7,100 7,040 Share-based incentive plans1 11,690 7,997 76,070 60,110 1 Vested during the period and based on IFRS 2 valuation (see Note 18) The overall increase in 2023 is mainly due to the increase in workforce in Canada following the Cor4 acquisition. 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, General Counsel and Corporate Secretary, Chief Operating Officer, Senior Vice President Canada, Vice President of Asset Management and Corporate Planning Canada and Vice President of Corporate Planning and Investor Relations. 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 2023 2022 Directors’ fees 665 597 Senior Management’s salaries, bonuses and other short-term benefits 8,198 7,210 Share-based incentive plans paid to Senior Management 7,933 6,207 16,796 14,014 ===== SIDA 42 ===== 42 Notes to the Consolidated Financial Statements For the years ended December 31, 2023 and 2022, AUDITED 27. 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, 2023: CAD Millions 2024 2025 2026 2027 2028 Thereafter Transportation service 1 27.9 29.2 38.4 43.4 46.4 555.6 Power2 9.8 9.8 9.8 9.8 9.8 – Total commitments 37.7 39.0 48.2 53.2 56.2 555.6 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 15MW at a weighted average price of CAD 74.92/MWH from January 1, 2024 - December 31, 2028. 28. RELATED PARTIES During the year 2023, the Group paid USD 365 thousand to the Lundin Foundation in respect of sustainability advisory services provided to the Group and USD 685 thousand to Orrön Energy in respect of office space rental for 2023. During the year 2023, Orrön Energy paid USD 657 thousand to the Group in respect of support services provided to Orrön Energy during 2023. 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. 29. SUBSEQUENT EVENTS No other events have occurred since December 31, 2023, that are expected to have a substantial effect on this report. ===== SIDA 43 ===== Corporate Office International Petroleum Corp Suite 2000 885 West Georgia Street Vancouver, BC V6C 3E8, 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, 2023 ===== SIDA 45 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 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 24. 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 37. 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, 2023, 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, 2023, 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, 2023, 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, 2023, 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 10 FINANCIAL REVIEW 13 • Financial Results 13 • Capital Expenditure 22 • Financial Position and Liquidity 23 • Non-IFRS Measures 24 • Off-Balance Sheet Arrangements 26 • Outstanding Share Data 26 • Contractual Obligations and Commitments 26 • Critical Accounting Policies and Estimates 27 • Transactions with Related Parties 27 • Financial Risk Management 27 RISK FACTORS 28 DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING 36 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 37 RESERVES AND RESOURCES ADVISORY 38 OTHER SUPPLEMENTARY INFORMATION 41 2 ===== SIDA 46 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 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 6, 2024 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, 2023 (“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 2000, 885 West Georgia Street, Vancouver, BC V6C 3E8, 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, 2023 December 31, 2022 Average Period end Average Year end 1 EUR equals USD 1.0816 1.1050 1.0539 1.0666 1 USD equals CAD 1.3496 1.3251 1.3015 1.3538 1 USD equals MYR 4.5598 4.5950 4.3995 4.4050 IPC completed the acquisition of Cor4 Oil Corp. (“Cor4”) on March 3, 2023. In accordance with IFRS, the Financial Statements have been prepared on that basis, with revenues and expenses related to the assets acquired in the Cor4 acquisition included in the Financial Statements from March 3, 2023. Certain historical and forecast 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 ”Cor4 Acquisition”, “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, 2023 HIGHLIGHTS 2023 Business Highlights • Average net production of approximately 49,600 boepd for the fourth quarter of 2023 was in line with the high end of the guidance range for the period (52% heavy crude oil, 13% light and medium crude oil and 35% natural gas).(1) • Full year 2023 average net production was 51,100 boepd, above the high end of annual guidance and a record high for IPC.(1) • Following the decision in Q1 2023 to develop Phase 1 of the Blackrod project, work on the project has progressed in line within the overall schedule and budget to first oil in late 2026. Key events include signing of the engineering, procurement and fabrication contract with the Engineering Procurement and Construction (EPC) contractor for the Central Processing Facility and advancement of facility engineering and fabrication works, access road expansion and site civil preparation works, and drilling operations. • Successfully integrated the Suffield area assets acquired from Cor4 Oil Corp. (Cor4) in March 2023 and executed the drilling program in the Ellerslie play with eight wells drilled in 2023. • Production sustaining Pad L at Onion Lake Thermal (OLT) successfully brought online, supporting record average daily production in 2023 from the OLT asset. • Sale of small non-core assets in Canada for MUSD 20, at a significant premium to 2P reserves net present value.(2) • In Malaysia, successfully completed planned maintenance turnaround at the Bertam field on scope, schedule, and budget. • In France, successfully delivered three new production wells at Villeperdue West and one side-track well at Merisier. • 9.3 million common shares purchased and cancelled from December 5, 2022 to December 4, 2023 under IPC’s 2022/2023 NCIB and a further 1.8 million common shares purchased for cancellation during December 2023 and January 2024 under the renewed 2023/2024 NCIB. 7% of IPC’s common shares outstanding were reduced through the NCIB in 2023. • In Q3 2023, published IPC’s fourth annual Sustainability Report and its first stand-alone report aligned with the Task Force on Climate-Related Financial Disclosures (TCFD). • Commitment to reduce IPC’s net emissions intensity to 20 kg CO2/boe by 2025, is extended to remain at that level through end 2028. 2023 Financial Highlights • Operating costs per boe of USD 18.3 for the fourth quarter of 2023 and USD 17.6 for the full year in line with full year guidance of USD 17.5 to 18 per boe.(3) • Strong operating cash flow (OCF) generation for the fourth quarter and full year 2023 amounted to MUSD 74 and MUSD 353, respectively.(3) • Capital and decommissioning expenditures of MUSD 130 for the fourth quarter and MUSD 327 for the full year 2023, in line with most recent full year guidance of MUSD 330. • Positive free cash flow (FCF) generation for the full year 2023 of MUSD 3, with negative FCF generation of MUSD 65 for the fourth quarter in line with expectations and taking into account the significant capital expenditures during the quarter. FCF before 2023 Blackrod capital expenditure of MUSD 240, was MUSD 243. (3) • Net cash of MUSD 58 and gross cash of MUSD 517 as at December 31, 2023. (3) • Net result of MUSD 30 for the fourth quarter of 2023 and MUSD 173 for the full year 2023. • Further strengthened IPC’s financial position with an increase of IPC’s bonds to MUSD 450 due February 2027 and an increase of IPC’s undrawn Canadian revolving credit facility to MCAD 180. Reserves and Resources • Total 2P reserves as at December 31, 2023 of 468 MMboe, representing a reserves replacement ratio of 78% compared to year-end 2022, with a reserves life index (RLI) of 27 years. (1)(2) • Contingent resources (best estimate, unrisked) as at December 31, 2023 of 1,145 MMboe.(1)(2) • 2P reserves net asset value (NAV) as at December 31, 2023 of MUSD 3,087 (10% discount rate). (1)(2)(4)(5) 2024 Annual Guidance • Full year 2024 average net production forecast at 46,000 to 48,000 boepd. (1) • Full year 2024 operating costs guidance forecast at USD 18 to 19 per boe.(3) • Full year 2024 OCF guidance estimated at between MUSD 261 to 382 (assuming Brent USD 70 to 90 per boe). (3) • Full year 2024 capital and decommissioning expenditures guidance forecast at MUSD 437, including MUSD 362 relating to continued development of Phase 1 of the Blackrod project. • Full year 2024 FCF ranges from approximately MUSD 144 to 268 (assuming Brent USD 70 to 90 per boe) before taking into account proposed Blackrod capital expenditures, or MUSD -218 to -94 including proposed Blackrod capital expenditures. (3) 4 ===== SIDA 48 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Business Plan Production and Cash Flow Guidance • 2024 – 2028 business plan forecasts: • average net production forecast approximately 55,000 boepd. (1) • capital expenditure forecast of USD 11 per boe, including USD 6 per boe for the Blackrod Phase 1 project. • operating costs forecast of USD 18 per boe.(3) • FCF forecast of approximately MUSD 900 to 1,800 (assuming Brent USD 75 to 95 per boe). (3)(7) • 2029 – 2033 business plan forecasts: • average net production forecast of approximately 65,000 boepd. (1) • capital expenditure forecast of USD 5 per boe. • operating costs forecast of USD 18 per boe.(3) • FCF forecast of approximately MUSD 1,750 to 2,800 (assuming Brent 75 to 95 USD per boe). (3)(7) Three months ended December 31 Year ended December 31 USD Thousands 2023 2022 2023 2022 Revenue 198,460 254,615 853,906 1,129,298 Gross profit 39,955 95,411 250,514 516,709 Net result 29,710 61,183 172,979 337,725 Operating cash flow(3) 73,634 113,668 353,048 622,947 Free cash flow(3) (64,688) 65,288 2,689 430,242 EBITDA(3) 66,284 125,651 350,618 639,480 Net Cash(3) 58,043 175,098 58,043 175,098 5 ===== SIDA 49 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 OPERATIONS REVIEW Business Overview IPC’s strategy since launching IPC in April 2017 remains unchanged: to deliver operational excellence through responsible operatorship, maintain financial resilience, maximise the value of our resource base, target growth organically and through acquisitions, and deliver stakeholder returns. IPC has followed through on this vision resulting in material value creation for all stakeholders through efficient capital allocation and operational proficiency. Since inception, IPC has sustained no material safety incidents across all operating domains, delivered within or ahead of guidance every reporting year, increased the Reserves Life Index (RLI) from 8 years to 27 years largely through 5 accretive acquisitions, and cancelled over 62.5 million common shares. The company is strongly positioned to continue following through on our strategy supported by a strong balance sheet to start 2024 with net cash of USD 58 million and material production growth expected from the Blackrod Phase 1 development with first oil expected in late 2026.(3) Following a year of exceptionally high oil and gas prices in 2022 with Brent prices averaging over USD 100 per barrel for the full year 2022, IPC continued to benefit in 2023 from strong oil benchmark prices, with average Brent prices over USD 82 per barrel for the full year. Quarterly average Brent prices during 2023 ranged between USD 78 to USD 87 per barrel. Strong oil and gas demand is expected to continue in 2024 which, along with such factors as OPEC+ decisions to curtail supply, potential market and transportation disruptions due to ongoing geopolitical tensions and current global observed crude inventory levels are at the bottom end of the five-year average could limit downside risks on commodity prices in 2024. These positive factors may be partially offset by increased forecast supply from countries such as the United States in a Presidential election year, which could be expected to limit price upside. In Canada, fourth quarter 2023 West Texas Intermediate (WTI) to Western Canadian Select (WCS) crude price differentials averaged around USD 22 per barrel, with average differentials of around USD 18.5 for the full year. The Trans-Mountain (TMX) pipeline is currently expected to commence line-fill in the first half of 2024 which should benefit the WTI/WCS differentials during 2024 and into the future. IPC has hedged the WTI/WCS differential for approximately 70% of our Canadian crude production at USD 15 per barrel and hedged 25% of our WTI exposure for approximately USD 81 per barrel for 2024. Gas markets in 2023 witnessed a substantial decrease from the 2022 average AECO benchmark prices above CAD 5 per Mcf. The average AECO gas price was CAD 2.30 per Mcf for the fourth quarter of 2023, and an average of CAD 2.60 for the full year 2023. IPC’s realized prices for gas were CAD 2.55 per Mcf for the fourth quarter of 2023 and CAD 3.36 per Mcf for the full year 2023 taking into account hedges in place until October 31, 2023. IPC benefits from a well-balanced mix of production comprising approximately 54% Canadian Crude, 33% Canadian Natural Gas and 13% Brent weighted oil, on average over 2023. With strong commodity pricing, combined with delivering operational excellence above the high end of IPC’s 2023 guidance, IPC has again been able to deliver a very strong financial performance in the fourth quarter and throughout the full year 2023. Fourth Quarter and Full Year 2023 Highlights During the fourth quarter of 2023, IPC’s assets delivered average net production of 49,600 boepd, in line with high-end guidance for the quarter. This was made possible by high operational performance across all of IPC’s assets as well as the production contribution from IPC’s 2023 investment program in Canada and France, notwithstanding some downtime from two production wells in Malaysia through Q4 which have now been worked over and are back on stream as of end January 2024. Full year 2023 average net production of 51,100 boepd was a record high for IPC and on target with guidance of greater than 50,000 boepd.(1) IPC’s operating costs per boe for the fourth quarter of 2023 was USD 18.3. Full year 2023 operating costs per boe was USD 17.6, in line with guidance of USD 17.5 to 18 per boe.(3) Operating cash flow (OCF) generation for the fourth quarter of 2023 was USD 74 million. Full year 2023 OCF was USD 353 million in line with the most recent guidance of USD 340 to 365 million.(3) Capital and decommissioning expenditure for the fourth quarter of 2023 was USD 130 million. Full year 2023 capital and decommissioning expenditure of USD 327 million was in line with guidance of USD 330 million. Free cash flow (FCF) generation was in line with guidance at negative USD 65 million during the fourth quarter of 2023, reflecting the higher level of capital expenditure on the Blackrod Phase 1 development project. Full year 2023 FCF generation was USD 3 million, at the higher end of the most recent guidance of USD -65 to 5 million.(3) As at December 31, 2023, IPC’s net cash position was USD 58 million. IPC’s gross cash on the balance sheet amounts to USD 517 million which provides IPC with significant financial strength to continue progressing its strategies in 2024, including advancing the Phase 1 Blackrod development, returning value to shareholders through the 2023/2024 NCIB, and remaining opportunistic to M&A.(3) 6 ===== SIDA 50 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Blackrod Project In Q1 2023, IPC announced the decision to advance the development of Phase 1 of the Blackrod project. Development capital expenditure to first oil is estimated at USD 850 million nominal. First oil of the Phase 1 development is estimated to be in late 2026, with forecast net production of 30,000 bopd by 2028. The Blackrod Phase 1 development targets 218 million barrels of 2P reserves and the sanction case WTI breakeven estimated as of January 1, 2023, using the December 31, 2022 price forecasts of IPC’s qualified independent reserves evaluator, Sproule Associates Limited (Sproule), was USD 59 per barrel assuming a 10% discount rate. Following capital expenditure of USD 240 million invested in 2023, the project is forecast to add USD 981 million to IPC’s 2P reserves net present value (NPV) as at January 1, 2024, with a WTI breakeven of USD 54.5 per barrel assuming a 10% discount rate, using Sproule’s December 31, 2023 price forecasts. IPC forecasts capital expenditure in 2024 for the Blackrod project of USD 362 million, with the remainder of the estimated total project budget to be invested prior to first oil. With greater than 1 billion barrels of contingent resources (best estimate, unrisked) remaining, Blackrod presents material upside to future phase expansions beyond the initial first Phase of development.(1)(2)(4) Project activities for the multi-year Phase 1 development have progressed in line with schedule and budget. Following the successful completion of Front-End Engineering and Design (FEED) studies through 2022, IPC formerly established a partnership with the Engineering, Procurement and Construction (EPC) contractor in 2023 through contractual commitments for the Central Processing Facility (CPF). As at the end of 2023, major long lead items have been procured, fabrication has commenced, site civil and commercial road expansion works have advanced, drilling is underway, and third-party pipeline commercial agreements are progressing according to plan. Following significant project milestones achieved through 2023, IPC is well positioned to continue advancing responsible development of the Blackrod Phase 1 development through 2024. With a combination of contractual commitments and financial foreign exchange hedges locked in at more favourable rates than assumed at project sanction, IPC sits comfortably within the overall budget and schedule guidance to first oil. IPC intends to fund the remaining Phase 1 development costs with forecast cash flow generated by its operations and cash on hand.(3) M&A IPC was pleased to close the strategic acquisition of Cor4 in March 2023 for a consideration of USD 62 million. The acquisition, located in the Suffield area, brought in 15.9 MMboe of 2P reserves as at January 1, 2023 and delivered greater than 5,000 boepd through 2023. The asset holds high quality mineral rights within the Ellerslie formation, an attractive feature that crystallised through 2023 as eight wells were successfully drilled into this play supporting higher than forecast production rates. The acquired asset team has been effectively integrated within IPC and further synergies within Suffield area are of continued focus as we seek to unlock further value potential.(1)(2) Following the strategic divestiture of small non-core production and land assets in the greater John Lake area in Canada announced in Q3 2023, IPC further sold non-producing lands in Q4 for a consideration of USD 3.5 million. The total proceeds in aggregate from the non-core dispositions in Q3 and Q4 was in excess of USD 20 million. The 2P reserves and NPV10 as of January 1, 2023 were 0.6 MMboe and USD 7.7 million respectively for the divested properties.(2)(4) IPC continues to review potential M&A opportunities. IPC has added over USD 2.5 billion of aggregate value in FCF generation and 2P reserves NPV increases, from IPC’s last 5 acquisitions.(3)(4) Stakeholder Returns: Normal Course Issuer Bid During the period of December 5, 2022 to December 4, 2023, IPC purchased and cancelled an aggregate of approximately 9.3 million common shares under the 2022/2023 normal course issuer bid / share repurchase program (NCIB). The average price of shares purchased under the 2022/2023 NCIB was SEK 102 / CAD 13.0 per share. In Q4 2023, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 8.3 million common shares over the period of December 5, 2023 to December 4, 2024. Under the 2023/2024 NCIB, IPC repurchased and cancelled approximately 1.2 million common shares in December 2023. By the end of January 2024, IPC repurchased for cancellation over 600,000 common shares under the 2023/2024 NCIB. The average price of common shares purchased under the 2023/2024 NCIB during December 2023 and January 2024 was SEK 114.5 / CAD 15 per share. As at February 6, 2023, IPC had a total of 126,479,966 common shares issued and outstanding, of which IPC holds 102,200 common shares in treasury. Notwithstanding the record level of capital investment forecast for 2024, IPC confirms its intention to continue to purchase and cancel common shares under the 2023/2024 NCIB to the remaining limit of 6.5 million common shares by December 4, 2024. This would result in the cancellation of 6.5% of shares outstanding as at the beginning of December 2023. 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. 7 ===== SIDA 51 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Environmental, Social and Governance (ESG) Performance Responsible operatorship and ensuring that IPC adheres to the highest principles of business conduct have been integral parts of how IPC does business since it started in 2017. With the publication of IPC’s second quarter 2023 financial report, IPC was very pleased to publish its fourth Sustainability Report and its first stand-alone report aligned with the Task Force on Climate-Related Financial Disclosures. IPC is committed to the continued advancement of ESG practices in its sustainability focus areas. The Group’s six sustainability priorities are: • Ethics & Integrity • Rewarding Workplace • Health & Safety • Community Engagement • Climate Action • Environmental Stewardship As part of IPC’s commitment to operational excellence, its objective is to reduce risk and eliminate hazards to prevent the occurrence of accidents, ill health, and environmental damage, as these are essential to the success of IPC’s operations. During the fourth quarter and for the full year 2023, IPC recorded no material safety or environmental incidents. With respect to climate action, as previously announced, IPC targets a reduction of 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. IPC has extended its commitment to remain at 2025 levels of 20 kg CO2/boe through to the end of 2028. Reserves, Resources and Value As at the end of December 2023, IPC’s 2P reserves are 468 MMboe. During 2023, IPC replaced 78% of the annual 2023 production. The reserves life index (RLI) as at December 31, 2023, remains at approximately 27 years.(1)(2) The net present value (NPV) of IPC’s 2P reserves as at December 31, 2023 was USD 3,023 million. IPC’s net asset value (NAV) was USD 3,081 or SEK 244 / CAD 32 per share as at December 31, 2023.(1)(2)(4)(5)(6) In addition, IPC’s best estimate contingent resources (unrisked) as at December 31, 2023 are 1,145 MMboe, ofwhich 1,066 MMboe relate to future potential phases of the Blackrod project.(1)(2) 2024 Budget and Operational Guidance IPC is pleased to announce its 2024 average net production guidance is 46,000 to 48,000 boepd. IPC forecasts operating costs for 2024 to be USD 18 to 19 per boe.(1)(3) IPC forecasts FCF generation based on its 2P reserves base of in aggregate of more than USD 900 to 1,800 million over the period of 2024 to 2028. In addition, IPC forecasts FCF generation of USD 1,750 to 2,800 million over the period of 2029 to 2033.(2)(3)(7) IPC’s 2024 capital and decommissioning expenditure budget is USD 437 million, with USD 362 million forecast relating to the Phase 1 development of the Blackrod project. The remainder of the 2024 budget in Canada includes drilling at the Suffield and Ferguson assets, further development of the Mooney asset, and ongoing optimization work. IPC also completed well workover operations in Malaysia by January 2024 and expects to conduct technical studies for future development potential. Following the successful execution of the 2023 drilling campaign in France, the subsurface teams are maturing drilling targets within the Paris Basin. 2024 is set to be a record growth investment year for IPC, we have therefore set a limited sustaining capital expenditure plan of USD 75 million, inclusive of decommissioning, across the producing assets in the portfolio. With robust cashflow being generated from the producing assets and gross cash resources of USD 517 million, IPC intends to fully complete the remaining share buybacks available under the NCIB program through 2024. 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 2024. Further details regarding IPC’s proposed 2024 budget and operational guidance will be provided at IPC’s Capital Markets Day presentation to be held on February 6, 2024 at 14:00 GMT. A copy of the Capital Markets Day presentation will be available on IPC’s website at www.international-petroleum.com. 8 ===== SIDA 52 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 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. IPC completed the acquisition of Cor4 Oil Corp. (Cor4) on March 3, 2023. The Financial Statements 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 historical 2023 operational and financial information included in the MD&A, including production, operating costs, OCF , FCF and EBITDA related to the assets acquired in the Cor4 acquisition, are reported based on the effective date of the Cor4 acquisition of January 1, 2023. (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. Reserves replacement ratio is based on 2P reserves of 471.5 MMboe as at December 31, 2022 (not including 2P reserves related to the Brooks assets acquired in the Cor4 acquisition), sales production during 2023 of 17.7 MMboe, net additions to 2P reserves during 2023 of 16.0 MMboe, other revisions downward of 2.2 MMboe, and 2P reserves of 468 MMboe as at December 31, 2023. (3) Non-IFRS measure, see “Non-IFRS Measures” below and in the MD&A. (4) 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. (5) NAV is calculated as NPV plus net cash of USD 58 million as at December 31, 2023. (6) NAV per share is based on 126,992,066 IPC common shares outstanding as at December 31, 2023. NAV per share is not predictive and may not be reflective of current or future market prices for IPC common shares. (7) Estimated FCF generation is based on IPC’s current business plans over the periods of 2024 to 2028 and 2029 to 2033. Assumptions include average net production of approximately 55 Mboepd over the period of 2024 to 2028, average net production of approximately 65 Mboepd over the period of 2029 to 2033, average Brent oil prices of USD 75 to 95 per boe 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 19, 2024 (USD 1,378 million based on 113.6 SEK/share, 126.99 million IPC shares outstanding and exchange rate of 10.47 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” below. 9 ===== SIDA 53 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Operations Overview 2023 Overview In 2023, IPC successfully demonstrated its commitment to operational excellence, with record annual net average production and no material safety incidents or harm to the environment. In Canada, the Blackrod Phase 1 development has progressed in accordance with plan. Initial construction camps have been installed and site preparations have been executed to allow for critical facility and drilling equipment delivery in Q1 2024. The major EPC contract has been signed for the central processing facility, bringing a higher degree of certainty for a significant portion of the Phase 1 capital expenditure to first oil. Drilling operations commenced in Q4 2023, with the first utility wells successfully executed in line with expectations. At Onion Lake Thermal, daily production is touching facility nameplate capacity of 14,000 boepd with the new production sustaining Pad L brought online ahead of schedule in Q3 2023. At Suffield, all eight planned new production wells in the exciting Ellerslie play have been brought online and are producing ahead of expectations. In France, all three of the budgeted Villeperdue West oil wells and the Merisier side-track oil well have been successfully brought online with production performing ahead of forecast. At Bertam in Malaysia, the two planned production well workovers have progressed in line with plan with the first well now back online and the second well expected to follow early in Q1 2024. Reserves and Resources The 2P reserves attributable to IPC’s oil and gas assets are 468 MMboe as at December 31, 2023, as certified by independent third party reserve auditors. The proved plus probable reserve life index (RLI) as at December 31, 2023, is approximately 27 years. Best estimate contingent resources as at December 31, 2023, are 1,145 MMboe (unrisked). See “Reserves and Resources Advisory” below. Production Average daily net production for the fourth quarter 2023 was in line with IPC’s high end guidance at 49,600 boepd. The quarter marks the end of a record production year for IPC with exceptional operational performance and the production benefit from the very successful 2023 development investment program. In Canada, strong operational performance has been supplemented by the newly drilled Suffield area Ellerslie production wells and ahead of expectations initial results from the new production sustaining Pad L at Onion Lake Thermal. In addition, IPC continues to see the benefit of 2023 development campaign in France with the three new wells at Villeperdue and the side-track well at Merisier producing above forecast. With exceptional operational delivery through 2023, IPC exits the year with a record net average production of 51,100 boepd, 1,100 boepd above the original 2023 Capital Markets Day (CMD) high end guidance of 50,000 boepd. The production during Q4 2023 with comparatives is summarized below: Production in Mboepd Three months ended December 31 Year ended December 31 2023 2022 2023 2022 Crude oil Canada – Northern Assets 15.5 16.0 15.5 15.6 Canada – Southern Assets1 11.4 9.0 11.8 8.7 Malaysia 2.5 5.2 3.8 5.3 France 2.8 2.7 2.8 2.7 Total crude oil production 32.2 32.9 33.9 32.3 Gas Canada – Northern Assets 0.4 0.1 0.4 0.1 Canada – Southern Assets 17.0 16.2 16.8 16.2 Total gas production 17.4 16.3 17.2 16.3 Total production 49.6 49.2 51.1 48.6 Quantity in MMboe 4.56 4.53 18.65 17.74 1 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”. 10 ===== SIDA 54 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 CANADA Production in Mboepd WI Three months ended December 31 Year ended December 31 2023 2022 2023 2022 - Oil Onion Lake Thermal 100% 13.6 13.1 13.3 12.7 - Oil Suffield Area1 100% 10.1 6.7 10.2 7.1 - Oil Ferguson 100% 1.3 2.3 1.5 1.6 - Oil Other 50-100% 1.9 2.9 2.3 2.9 - Gas1 ~100%2 17.4 16.3 17.2 16.3 Canada 44.3 41.3 44.5 40.6 1 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. 2 On a well count basis Production Net production from IPC’s Canadian assets during Q4 2023 was ahead of the high-end guidance at 44,300 boepd with continued strong operational performance at all the major producing assets. At Onion Lake Thermal, daily production has been stable close to the facility nameplate capacity of 14,000 boepd with four well pairs from production sustaining Pad L online ahead of schedule. The Suffield area oil and gas producing assets continue to deliver above forecast, where base well rate optimization has been supplemented by ahead of expectations production performance from the newly drilled Ellerslie play oil wells. Organic Growth and Capital Projects In Canada, the Blackrod Phase 1 development was sanctioned in Q1 2023. A reduced base business budget for the remainder of the assets in Canada was set for 2023 with a focus on oil well drilling in the Suffield Ellerslie formation and the completion of the next production sustaining Pad L at Onion Lake Thermal. During the fourth quarter, the Blackrod Phase 1 development progressed in accordance with plan. Site civil preparations and road expansion work have been completed in preparation for the key facility and drilling equipment delivery in Q1 2024. Drilling activity commenced on schedule in Q4 2023 and is progressing in line with expectations. As of the end of Q4 2023 in the Suffield area, the six originally planned Ellerslie play wells, as well as the two additional wells announced in Q3 2023, have been drilled, brought online and are performing ahead of expectations. At Onion Lake Thermal, daily production is stable close to the facility nameplate capacity of 14,000 boepd with four well pairs from production sustaining Pad L online. MALAYSIA Production in Mboepd WI Three months ended December 31 Year ended December 31 2023 2022 2023 2022 Bertam 100% 2.5 5.2 3.8 5.3 Production Net production at Bertam in Malaysia in Q4 2023 was below guidance at 2.5 boepd, with two production wells offline awaiting workover intervention in the quarter. The two workovers were completed and both wells were back on-stream as of end January 2024. Organic Growth and Capital Projects In Malaysia, field development studies have progressed in line with expectations as IPC matures the remaining undeveloped potential of the Bertam field following the successful results from the latest development drilling campaign in the north east of the field. 11 ===== SIDA 55 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 FRANCE Production in Mboepd WI Three months ended December 31 Year ended December 31 2023 2022 2023 2022 France - Paris Basin 100%1 2.5 2.3 2.4 2.4 - Aquitaine 50% 0.3 0.4 0.4 0.3 2.8 2.7 2.8 2.7 1 Except for the working interest in the Dommartin Lettree field of 43% Production Net production in France during Q4 2023 was in line with the guidance at 2,800 boepd. Organic Growth In France, all three Villeperdue West oil wells and the Merisier side-track oil well have been drilled, completed and brought online with production performing ahead of forecast. IPC continues to mature future development projects in France, with focus towards the undeveloped resource base within the Paris Basin supported by the positive results following the 2023 development campaign. 12 ===== SIDA 56 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 FINANCIAL REVIEW Financial Results Selected Annual Financial Information Selected consolidated statement of operations is as follows: USD Thousands 2023 2022 2021 Revenue 853,906 1,129,298 666,409 Gross profit 250,514 516,709 210,321 Net result 172,979 337,725 146,059 Earnings per share – USD 1.31 2.30 0.94 Earnings per share fully diluted – USD 1.28 2.25 0.92 Operating cash flow1 353,048 622,947 336,732 Free cash flow1 2,689 430,242 262,884 EBITDA1 350,618 639,480 330,754 Net cash / (debt) at period end1 58,043 175,098 (94,312) 1 See definition on page 24 under “Non-IFRS measures” Summarized consolidated balance sheet information is as follows: USD Thousands December 31, 2023 December 31, 2022 December 31, 2021 Non-current assets 1,372,388 1,041,051 1,122,514 Current assets 690,597 638,566 151,160 Total assets 2,062,985 1,679,617 1,273,674 Total non-current liabilities 779,838 564,381 331,152 Current liabilities 202,888 149,905 94,979 Total liabilities 982,726 714,286 426,131 Net assets 1,080,259 965,331 847,543 Working capital (including cash) 487,709 488,661 56,181 13 ===== SIDA 57 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Selected Interim Financial Information Selected interim condensed consolidated statement of operations is as follows: USD Thousands 2023 Q4-23 Q3-23 Q2-23 Q1-23 2022 Q4-22 Q3-22 Q2-22 Q1-22 Revenue 853,906 198,460 257,366 205,564 192,516 1,129,298 254,615 299,361 315,540 259,782 Gross profit 250,514 39,955 93,429 52,747 64,383 516,709 95,411 140,489 161,709 119,100 Net result 172,979 29,710 71,681 32,025 39,563 337,725 61,183 90,503 105,217 80,822 Earnings per share – USD 1.31 0.23 0.56 0.24 0.29 2.30 0.45 0.63 0.70 0.52 Earnings per share fully diluted – USD 1.28 0.22 0.54 0.24 0.28 2.25 0.44 0.62 0.68 0.51 Operating cash flow1 353,048 73,634 119,142 84,372 75,900 622,947 113,668 171,654 192,515 145,110 Free cash flow1 2,689 (64,688) 34,703 16,415 16,259 430,242 65,288 116,681 151,792 96,479 EBITDA1 350,618 66,284 123,054 85,201 76,079 639,480 125,651 174,328 194,038 145,463 Net cash / (debt) at period end1 58,043 58,043 83,097 63,548 66,956 175,098 175,098 88,615 14,382 (42,367) 1 See definition on page 24 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 of the Suffield assets (including the Brooks assets acquired as part of the Cor4 acquisition) and the Ferguson asset). This is consistent with the internal reporting provided to IPC management. The following tables present certain segment information. 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 14 ===== SIDA 58 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Three months ended – December 31, 2022 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 101,127 52,721 44,361 29,095 – 227,304 NGLs – 142 – – – 142 Gas 256 35,656 – – – 35,912 Net sales of oil and gas 101,383 88,519 44,361 29,095 – 263,358 Change in under/over lift position – – – (7,642) – (7,642) Royalties (10,006) (8,989) – (1,864) – (20,859) Hedging settlement 12,308 7,277 – – – 19,585 Other operating revenue – – – 173 – 173 Revenue 103,685 86,807 44,361 19,762 – 254,615 Operating costs (23,247) (32,964) (9,394) (8,900) – (74,505) Cost of blending (39,494) (7,040) – – – (46,534) Change in inventory position (551) 124 (4,111) (54) – (4,592) Depletion and decommissioning costs (8,256) (10,591) (8,667) (2,806) – (30,320) Depreciation of other tangible fixed assets – – (2,695) – – (2,695) Exploration and business development costs – – – – (558) (558) Gross profit/(loss) 32,137 36,336 19,494 8,002 (558) 95,411 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 costs (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 15 ===== SIDA 59 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Year ended – December 31, 2022 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 513,349 265,016 184,143 112,379 – 1,074,887 NGLs – 774 – – – 774 Gas 1,082 153,672 – – – 154,754 Net sales of oil and gas 514,431 419,462 184,143 112,379 – 1,230,415 Change in under/over lift position – – – (8,553) – (8,553) Royalties (59,353) (46,503) – (6,660) – (112,516) Hedging settlement 18,842 283 – – – 19,125 Other operating revenue – 111 – 716 – 827 Revenue 473,920 373,353 184,143 97,882 – 1,129,298 Operating costs (101,443) (115,574) (35,051) (35,588) – (287,656) Cost of blending (155,375) (33,797) – – – (189,172) Change in inventory position 721 317 (1,916) 720 – (158) Depletion and decommissioning costs (33,097) (41,980) (34,687) (12,277) – (122,041) Depreciation of other tangible fixed assets – – (10,787) – – (10,787) Exploration and business development costs 97 – – – (2,872) (2,775) Gross profit/(loss) 184,823 182,319 101,702 50,737 (2,872) 516,709 Three months and year ended December 31, 2023, Review Revenue Total revenue amounted to USD 198,460 thousand for Q4 2023, compared to USD 254,615 thousand for Q4 2022 and USD 853,906 thousand for the year ended December 31, 2023 compared to USD 1,129,298 thousand for the year ended December 31, 2022 and is analyzed as follows: USD Thousands Three months ended December 31 Year ended December 31 2023 2022 2023 2022 Crude oil sales 211,438 227,304 871,221 1,074,887 Gas and NGL sales 15,101 36,054 68,510 155,528 Change in under/overlift position (8,442) (7,642) 400 (8,553) Royalties (27,009) (20,859) (106,297) (112,516) Hedging settlement 6,959 19,585 18,928 19,125 Other operating revenue 413 173 1,144 827 Total revenue 198,460 254,615 853,906 1,129,298 The main components of total revenue for the three months and year ended December 31, 2023, and December 31, 2022, respectively, are detailed below. 16 ===== SIDA 60 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Crude oil sales 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 Three months ended – December 31, 2022 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 101,127 52,721 44,361 29,095 227,304 - Quantity sold in bbls 1,824,392 900,832 473,071 330,014 3,528,309 - Average price realized USD per bbl 55.43 58.52 93.77 88.16 64.42 Crude oil revenue was 7% lower in Q4 2023 compared to Q4 2022 mainly due to lower oil prices. Canadian - Southern Assets sales volumes are 21% higher in Q4 2023 compared to Q4 2022 as a result of the Cor4 acquisition in Q1 2023 and Malaysia sales volume are 62% lower in Q4 2023 compared to Q4 2022 as a result of two production wells offline awaiting workover intervention. The Suffield area assets and Onion Lake crude oil in Canada are 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 2023, WTI averaged USD 79 per bbl compared to USD 83 per bbl for Q4 2022 and the average discount to WCS used in IPC’s pricing formula was USD 22 per bbl compared to USD 26 per bbl for Q4 2022. The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia during Q4 2023 and two cargo liftings in Q4 2022. Produced unsold oil barrels from Bertam at the end of Q4 2023 amounted to 163,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 84 per bbl for Q4 2023 compared to USD 89 per bbl for the comparative period. 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 Year ended – December 31, 2022 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 513,349 265,016 184,143 112,379 1,074,887 - Quantity sold in bbls 6,880,263 3,492,721 1,646,301 1,143,130 13,162,415 - Average price realized USD per bbl 74.61 75.88 111.85 98.31 81.66 The Suffield area assets and Onion Lake crude oil in Canada are 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. 17 ===== SIDA 61 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Crude oil revenue was lower by 19% during the year ended December 31, 2023 compared to the year ended December 31, 2022 mainly due to lower oil prices despite higher sales volumes driven by the Cor4 acquisition and Onion Lake performance. The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. WTI averaged USD 78 per bbl for the year ended December 31, 2023 compared to USD 94 per bbl for the comparative period and the average discount to WCS used in IPC’s pricing formula was USD 19 per bbl compared to USD 18 per bbl for the comparative period. The realized sales price for Malaysia and France is based on Brent crude oil prices and the average market Brent crude oil price was USD 83 per bbl for the year ended December 31, 2023 compared to USD 101 per bbl for the comparative period. Gas and NGL sales Three months ended – December 31, 2023 Canada – Southern Assets Canada – Northern Assets Total Gas and NGL sales - Revenue in USD thousands 14,983 118 15,101 - Quantity sold in Mcf 8,585,805 77,185 8,662,990 - Average price realized USD per Mcf 1.75 1.53 1.74 Three months ended – December 31, 2022 Canada – Southern Assets Canada – Northern Assets Total Gas and NGL sales - Revenue in USD thousands 35,798 256 36,054 - Quantity sold in Mcf 8,256,010 70,093 8,326,103 - Average price realized USD per Mcf 4.34 3.65 4.33 Gas and NGL sales revenue was 58% lower for Q4 2023 compared to Q4 2022 mainly due to the lower achieved gas price. IPC’s achieved gas price is based on AECO pricing plus a premium. For Q4 2023, IPC realized an average price of CAD 2.33 per Mcf compared to AECO average pricing of CAD 2.29 per Mcf. Year ended – December 31, 2023 Canada – Southern Assets Canada – Northern Assets Total Gas and NGL sales - Revenue in USD thousands 68,137 373 68,510 - Quantity sold in Mcf 33,221,660 227,032 33,448,692 - Average price realized USD per Mcf 2.05 1.64 2.05 Year ended – December 31, 2022 Canada – Southern Assets Canada – Northern Assets Total Gas and NGL sales - Revenue in USD thousands 154,446 1,082 155,528 - Quantity sold in Mcf 32,699,017 264,673 32,963,690 - Average price realized USD per Mcf 4.72 4.09 4.72 Gas and NGL sales revenue was 56% lower for the year ended December 31, 2023 compared to the year ended December 31, 2022 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, 2023, IPC realized an average price of CAD 2.73 per Mcf compared to AECO average pricing of CAD 2.61 per Mcf. 18 ===== SIDA 62 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 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. The oil and gas pricing contracts are not entered into for speculative purposes. The realized hedging settlement for the year ended December 31, 2023 amounted to a gain of USD 18,928 thousand and consisted of a gain of USD 15,664 thousand on the gas contracts and a gain of USD 3,264 thousand on the oil 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 126,414 thousand for Q4 2023 compared to USD 125,631 thousand for Q4 2022 and USD 491,303 thousand for the year ended December 31, 2023 compared to USD 476,987 thousand for the comparative period, and is analyzed as follows: Three months ended – December 31, 2023 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Other3 Total Operating costs1 38,651 23,868 12,091 11,679 (2,921) 83,368 USD/boe2 14.80 16.39 51.74 45.26 n/a 18.28 Cost of blending 6,872 37,601 – – – 44,473 Change in inventory position (873) 638 (1,217) 25 – (1,427) Production costs 44,650 62,107 10,874 11,704 (2,921) 126,414 Three months ended – December 31, 2022 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Other3 Total Operating costs1 32,964 23,247 13,534 8,900 (4,140) 74,505 USD/boe2 14.21 15.72 28.12 33.75 n/a 16.45 Cost of blending 7,040 39,494 – – – 46,534 Change in inventory position (124) 551 4,111 54 – 4,592 Production costs 39,880 63,292 17,645 8,954 (4,140) 125,631 Year ended – December 31, 2023 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Other3 Total Operating costs1 155,178 94,817 50,032 36,288 (14,353) 321,962 USD/boe2 15.51 16.33 35.87 36.27 n/a 17.63 Cost of blending 26,792 146,204 – – – 172,996 Change in inventory position (952) 448 (3,358) 207 – (3,655) Production costs 181,018 241,469 46,674 36,495 (14,353) 491,303 19 ===== SIDA 63 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Year ended – December 31, 2022 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Other3 Total Operating costs1 115,574 101,443 51,476 35,589 (16,425) 287,657 USD/boe2 12.71 17.75 26.72 35.04 n/a 16.21 Cost of blending 33,797 155,375 – – – 189,172 Change in inventory position (317) (721) 1,916 (720) – 158 Production costs 149,054 256,097 53,392 34,869 (16,425) 476,987 1 See definition on page 24 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 includes Cor4 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 39.24 and USD 19.52 for Q4 2023 and Q4 2022 respectively and USD 25.58 and USD 18.20 for the year ended December 31, 2023 and December 31, 2022, respectively. Operating costs Operating costs amounted to USD 83,368 thousand for Q4 2023 compared to USD 74,505 thousand for Q4 2022 and USD 321,962 thousand for the year ended December 31, 2023 compared to USD 287,657 for the year ended December 31, 2022. The increase in costs in 2023 compared to 2022 is due mainly to the Cor4 acquisition in Q1 2023, increased production and activity levels. Operating costs per boe amounted to USD 18.28 per boe in Q4 2023 below guidance for the quarter and compared with USD 16.45 per boe in Q4 2022. The operating cost per boe in Malaysia is higher in Q4 2023 compared with Q4 2022 as a result of the lower production due to two producing wells offline. Operating costs per boe for the year ended December 31, 2023 amounted to USD 17.63 per boe which was within the full year operating cost guidance of between USD 17.5 to 18 per boe. Cost of blending For the Suffield area 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 majority of Onion Lake oil production has also been blended and exported by pipeline since April 2022 with the commissioning of a third party export pipeline from the Onion Lake field to the gathering system. The cost of the diluent amounted to USD 44,473 thousand for Q4 2023 compared to USD 46,534 thousand for Q4 2022 and USD 172,996 thousand for the year ended December 31, 2023 compared to USD 189,172 thousand for the comparative period. The decrease versus the comparative period is largely attributable to lower commodity pricing reflected in the cost of diluent partly offset by increased blending at Onion Lake following the commissioning of the pipeline in April 2022. 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 2023, IPC had crude entitlement of 163,000 barrels of oil on the FPSO Bertam facility being crude produced but not yet sold. The next Bertam lifting scheduled for February 2024. Depletion and decommissioning costs The total depletion of oil and gas properties amounted to USD 30,434 thousand for Q4 2023 compared to USD 30,320 thousand for Q4 2022 and USD 126,010 thousand for the year ended December 31, 2023 (including an adjustment for accelerated decommissioning activities amounting to USD 24,088 thousand) compared to USD 122,041 thousand for the year ended December 31, 2023. The depletion charge is analyzed in the following tables: Three months ended – December 31, 2023 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Depletion cost in USD thousands 14,654 9,165 2,982 3,633 30,434 USD per boe 5.61 6.30 12.76 14.08 6.67 Three months ended – December 31, 2022 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Depletion cost in USD thousands 10,591 8,256 8,667 2,806 30,320 USD per boe 4.57 5.58 18.01 11.22 6.69 20 ===== SIDA 64 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Year ended – December 31, 2023 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Depletion cost in USD thousands 56,897 37,295 17,800 14,018 126,010 USD per boe 5.68 6.42 12.76 14.01 6.89 Year ended – December 31, 2022 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Depletion cost in USD thousands 41,980 33,097 34,687 12,277 122,041 USD per boe 4.62 5.79 18.01 12.13 6.88 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 includes Cor4 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 decreased compared to the prior year following the extension to the Bertam field production sharing contract and consequent increase in field reserves announced at the end of 2022. In addition, the depletion rate in Canada - Southern Assets has increased compared to the prior year as a result of the Cor4 acquisition. Depreciation of other tangible fixed assets The total depreciation of other assets amounted to USD 1,309 thousand for Q4 2023 compared to USD 2,695 thousand for Q4 2022 and USD 7,812 thousand for the year ended December 31, 2023 compared to USD 10,787 thousand for the comparative period. This relates to the depreciation of the FPSO Bertam, which is being depreciated on a unit of production basis to August 2025, being the original Bertam field production sharing contract (PSC) expiry date, before the PSC extension to 2035. Exploration and business development costs The total exploration and business developments costs amounted to a cost of USD 348 thousand for Q4 2023 and a cost of USD 2,355 thousand for the year ended December 31, 2023 including Cor4 acquisition related costs amounting to USD 834 thousand. Sale of assets Sale of assets amounted to USD 19,018 thousand for the year ended December 31, 2023 and represents the sale of John Lake properties in Canada with gross proceeds of CAD 28.1 million (USD 20.8 million) and a net accounting gain on disposal of CAD 25.7 million (USD 19.0 million). Net financial items Net financial items amounted to a charge of USD 22,736 thousand for the year ended December 31, 2023, compared to a charge of USD 37,131 thousand for the year ended December 31, 2022, and included a non-cash net foreign exchange loss of USD 1,911 thousand for 2023 compared to a net foreign exchange loss of USD 7,872 thousand for 2022. The foreign exchange movements during the year ended December 31, 2023 are mainly resulting from the revaluation of intra-group loan funding balances. Excluding foreign exchange movements, the net financial items amounted to a charge of USD 20,825 thousand for the year ended December 31, 2023, compared to USD 29,259 thousand for the year ended December 31, 2022. The interest expense amounted to USD 25,635 thousand for the year ended December 31, 2023, compared to USD 20,689 thousand for the comparative period in 2022 and mainly related to the bond interest at a coupon rate of 7.25% per annum. Interest income generated on cash balances held in 2023 amounted to USD 21,774 thousand for the year ended December 31, 2023 and is higher than the comparative period of USD 6,966 thousand due mainly to higher interest rates and higher cash balances. The unwinding of the asset retirement obligation discount rate amounted to USD 13,408 thousand for year ended December 31, 2023, compared to USD 10,758 thousand for the year ended December 31, 2022. Income tax The corporate income tax amounted to a charge of USD 55,362 thousand for the year ended December 31, 2023, compared to a charge of USD 127,413 thousand for the year ended December 31, 2022 and has decreased due to the lower net financial result before tax. The current income tax charge amounted to USD 14,457 thousand in 2023 compared to USD 29,365 thousand in 2022 and mainly related to France and Malaysia. The current income tax charge included a windfall profits tax in France amounting to USD 10,915 thousand. No corporate income tax was payable in Canada in respect of the year ended December 31, 2023 due to the usage of historical tax pools. 21 ===== SIDA 65 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Capital Expenditure Development and exploration and evaluation expenditure incurred during the year ended December 31, 2023 was as follows: USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Development 23,454 255,159 17,873 16,204 312,690 Exploration and evaluation – – – 39 39 23,454 255,159 17,873 16,243 312,729 Capital expenditure of USD 312,729 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project and on the Pad L completion at Onion Lake Thermal, in France on the drilling of the Villeperdue West oil wells and in Malaysia on the well workovers. In addition, USD 5,821 thousand of capital expenditure was spent on the Brooks assets mainly on drilling from January 1, 2023 to the completion date of March 3, 2023. Cor4 Acquisition On March 3, 2023, IPC completed the acquisition of all of the issued and outstanding shares of Cor4 Oil Corp. (“Cor4”). Cor4 owned assets in the Brooks area, Alberta. At such date, Cor4 became an indirect wholly-owned subsidiary of IPC. On June 1, 2023, Cor4 was amalgamated 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. 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 reserve in equity (881) Total Consideration 62,211 Settled by: Cash payment 62,211 The Corporation performed a preliminary purchase price allocation for the Cor4 acquisition. The amounts disclosed above were determined provisionally pending the finalization of the valuation for those assets and liabilities. Up to twelve months from the effective date of the Cor4 acquisition, further adjustments may be made to the fair values assigned to the identifiable assets acquired and liabilities assumed. Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during the year ended December 31, 2023. 22 ===== SIDA 66 ===== Management’s Discussion and Analysis For the three months ended and 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%. Other tangible fixed assets Other tangible fixed assets amounted to USD 25,438 thousand as at December 31, 2023, which included USD 23,730 thousand in respect of the FPSO Bertam. The FPSO Bertam is being depreciated on a unit of production basis based to August 2025, being the original Bertam field PSC expiry date before the PSC extension to 2035. Financial Position and Liquidity Financing As at January 2022, the Group had a reserve-based lending (RBL) credit facility of USD 140 million in connection with its oil and gas assets in France and Malaysia and a RBL credit facility of CAD 300 million in connection with its oil and gas assets in Canada. In February 2022, IPC completed the issuance of USD 300 million of bonds, which mature in February 2027 and have a fixed coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group used a portion of the proceeds of the bonds to fully repay the outstanding RBL credit facilities, which were then cancelled. At the same time, the Group entered into 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, 2023, IPC had a nominal USD 450 million of bonds outstanding with maturity in February 2027. In Q1 2023, the Group increased the Canadian RCF from CAD 75 to CAD 150 million and extended the maturity to May 2025. In Q3 2023, the Group increased the Canadian RCF to CAD 165 million and in Q4 2023, the Group further increased the Canadian RCF to CAD 180 million. No cash amounts were drawn under the Canadian RCF as at December 31, 2023. As at December 31, 2023, IPC had a EUR 13 million unsecured credit facility in France (the “France Facility“), with maturity in May 2026. IPC commenced quarterly repayments of the French Facility in August 2022. The amount remaining outstanding under the France Facility as at December 31, 2023 was USD 9 million (EUR 8 million). Total net cash as at December 31, 2023 amounted to USD 58 million. IPC intends to fund the Blackrod Phase 1 development with cash on hand, forecast FCF generated by its operations and available credit facilities. The bond repayment obligations as at December 31, 2023, are classified as non-current as there are no mandatory repayments within the next twelve months. An amount of USD 3.6 million (EUR 3.2 million) drawn under the France Facility as at December 31, 2023 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, 2023. Cash and cash equivalents held amounted to USD 517 million as at December 31, 2023. Working Capital As at December 31, 2023, the Group had a net working capital balance including cash of USD 487,709 thousand compared to USD 488,661 thousand as at December 31, 2022. The difference as at December 31, 2023, from December 31, 2022 is mainly as a result of the increased cash following the tap issue offset by the payment for the Cor4 acquisition and the continuing NCIB program. 23 ===== SIDA 67 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Non-IFRS Measures In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by and the financial performance and condition of the Corporation. Management also uses non-IFRS measures internally in order to facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures are important supplemental measures of operating performance because they highlight trends in the core business that may not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties frequently use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the purpose of presenting information about management’s current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. “Operating cash flow” is calculated as revenue less production costs less current tax. Operating cash flow is used to analyze the amount of cash that is being generated available for capital investment and servicing debt. “Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures less general, administration and depreciation expenses before depreciation and less cash financial items. Free cash flow is used to analyze the amount of cash that is being generated by the business and that is available for such purposes as repaying debt, funding acquisitions and returning capital to shareholders. “EBITDA” is calculated as net result before financial items, taxes, depletion of oil and gas properties, exploration costs, impairment costs and depreciation and adjusted for non-recurring profit/loss on sale of assets and other income. “Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is used to analyze the cash cost of producing the oil and gas volumes. “Net debt” is calculated as bank loans and bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash equivalents less bank loans and bonds. Reconciliation of Non-IFRS Measures Operating cash flow The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements: USD Thousands Three months ended December 31 Year ended December 31 2023 2022 2023 2022 Revenue 198,460 254,615 853,906 1,129,298 Production costs (126,414) (125,631) (491,303) (476,986) Current tax 1,588 (15,316) (14,457) (29,365) Operating cash flow 73,634 113,668 348,146 622,947 The operating cash flow for the year ended December 31, 2023 including the operating cash flow contribution of the Cor4 acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 353,048 thousand. 24 ===== SIDA 68 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Free cash flow The following table sets out how free cash flow is calculated from figures shown in the Financial Statements: USD Thousands Three months ended December 31 Year ended December 31 2023 2022 2023 2022 Operating cash flow - see above 73,634 113,668 348,146 622,947 Capital expenditures (128,825) (42,792) (312,729) (157,662) Abandonment and farm-in expenditures1 (1,516) (1,085) (9,199) (6,962) General, administration and depreciation expenses before depreciation2 (5,762) (3,333) (16,886) (12,832) Cash financial items3 (2,219) (1,170) (5,812) (15,249) Free cash flow (64,688) 65,288 3,520 430,242 1 See note 20 to the Financial Statements 2 Depreciation is not specifically disclosed in the Financial Statements 3 See notes 5 and 6 to the Financial Statements. The free cash flow for the year ended December 31, 2023 including the free cash flow contribution of the Cor4 acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 2,689 thousand. EBITDA The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA: USD Thousands Three months ended December 31 Year ended December 31 2023 2022 2023 2022 Net result 29,710 61,183 172,979 337,725 Net financial items 6,509 6,002 22,736 37,131 Income tax 4,691 24,486 55,362 127,413 Depletion 30,434 30,320 101,922 122,041 Depreciation of other tangible fixed assets 1,309 2,695 7,812 10,787 Exploration and business development costs 348 558 2,355 2,775 Depreciation included in general, administration and depreciation expenses1 389 407 1,569 1,608 Sale of assets (7,106) – (19,018) – EBITDA 66,284 125,651 345,717 639,480 1 Item is not shown in the Financial Statements. The EBITDA for the year ended December 31, 2023 including the EBITDA contribution of the Cor4 acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 350,618 thousand. Operating costs The following table sets out how operating costs is calculated: USD Thousands Three months ended December 31 Year ended December 31 2023 2022 2023 2022 Production costs 126,414 127,495 491,303 483,646 Cost of blending (44,473) (46,534) (172,996) (189,172) Change in inventory position 1,427 (4,592) 3,655 (158) Operating costs 83,368 76,369 321,962 294,316 The operating costs for the year ended December 31, 2023 including the operating costs contribution of the Cor4 acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 328,763 thousand. 25 ===== SIDA 69 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Net cash The following table sets out how net cash is calculated: USD Thousands December 31, 2023 December 31, 2022 Bank loans (9,031) (12,142) Bonds1 (450,000) (300,000) Cash and cash equivalents 517,074 487,240 Net cash 58,043 175,098 1 The bond amount represents the redeemable value at maturity (February 2027). Off-Balance Sheet Arrangements IPC, through its subsidiary IPC Canada Ltd, has issued four letters of credit as follows: (a) CAD 2.6 million in respect of its obligations to purchase diluent; (b) CAD 0.8 million in respect of its obligations related to the Ferguson asset, increasing by CAD 0.1 million annually to a maximum of CAD 1.0 million; (c) CAD 1.3 million in respect of pipeline access; and (d) CAD 0.5 million in relation to the hedging of electricity prices. Outstanding Share Data The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. As at January 1, 2022, IPC had a total of 155,198,105 common shares issued and outstanding, of which IPC held 1,160,651 common shares in treasury. All common shares held in treasury as at January 1, 2022 were cancelled during January 2022. During 2022, under the normal course issuer bid/share repurchase program announced in December 2021 and renewed in December 2022 (NCIB), IPC purchased and cancelled an aggregate of 8,951,391 common shares. During Q2 2022, IPC commenced an offer to repurchase common shares under the substantial issuer bid (SIB). Under the SIB, IPC purchased and cancelled an aggregate of 8,258,064 common shares. As at December 31, 2022, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in treasury. Over the period of December 5, 2022 to December 4, 2023, IPC purchased and cancelled a total of 9,333,479 common shares under the NCIB (8,603,179 common shares purchased and cancelled in 2023). The NCIB was further renewed in Q4 2023 and IPC is entitled to purchase up to 8,342,119 common shares over the period of December 5, 2023 to December 4, 2024. During December 2023, IPC purchased and cancelled a total of 1,232,754 common shares under the renewed NCIB. 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. Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 40,697,533 common shares in IPC, representing 32.0% of the outstanding common shares as at December 31, 2023. In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on matters to be decided by the holders of IPC’s common shares. IPC has 4,440,062 IPC Share Unit Plan awards outstanding as at February 6, 2024 (321,512 awards granted in March 2021, 1,716,000 awards granted in May 2021, 4,333 awards granted in January 2022, 1,244,359 awards granted in March 2022, 2,391 awards granted in July 2022, 2,072 awards granted in January 2023, 1,143,708 awards granted in March 2023, 3,244 awards granted in July 2023 and 2,443 awards granted in January 2024). 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, 2023: CAD Millions 2024 2025 2026 2027 2028 Thereafter Transportation service 1 27.9 29.2 38.4 43.4 46.4 555.6 Power2 9.8 9.8 9.8 9.8 9.8 – Total commitments 37.7 39.0 48.2 53.2 56.2 555.6 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 15MW at a weighted average price of CAD 74.92/MWH from January 1, 2024 - December 31, 2028. 26 ===== SIDA 70 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Critical Accounting Policies and Estimates In connection with the preparation of the Corporation’s consolidated financial statements, 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. These assumptions, estimates and judgments are based on historical experience, current trends and other factors that they believe to be relevant at the time the financial statements are prepared. The management reviews the accounting policies, assumptions, estimates and judgments to ensure that the financial statements are presented fairly in accordance with IFRS. 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. Transactions with Related Parties During the year 2023, the Group paid USD 365 thousand to the Lundin Foundation in respect of sustainability advisory services provided to the Group and USD 685 thousand to Orrön Energy in respect of office space rental for 2023. During the year 2023, Orrön Energy paid USD 657 thousand to the Group in respect of support services provided to Orrön Energy during 2023. 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. Financial Risk Management As an international oil and gas exploration and production company, IPC is exposed to financial risks such as interest rate risk, currency risk, credit risk, liquidity risks as well as the risk related to the fluctuation in oil and gas prices. The Group seeks to control these risks through sound management practice and the use of internationally accepted financial instruments, such as oil and gas, condensate and electricity price, interest rate or foreign exchange hedges as the case may be. Financial instruments will be solely used for the purpose of managing risks in the business. As at December 31, 2023, the Corporation had entered into oil and gas, condensate and electricity price hedges – see below. Management believes that the cash resources, other current assets and cash flow from operations are sufficient to finance the Group’s operations and capital expenditures program over the next year. Capital Management The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its committed financial liabilities and work program requirements in order to create shareholder value. The Group may put in place new bonds or credit facilities, repay debt, or pursue other such restructuring activities as appropriate. Management of the Corporation will continuously monitor and manage the Group’s capital, liquidity and net debt position in order to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility. Price of Oil and Gas Prices of oil and gas are affected by the normal economic drivers of supply and demand as well as by financial investors and market uncertainty. Factors that influence these prices include operational decisions, prices of competing fuels, natural disasters, economic conditions, transportation constraints, political instability or conflicts or actions by major oil exporting countries. Price fluctuations will affect the Group’s financial position. Based on analysis of the circumstances, management assesses the benefits of forward hedging monthly sales contracts for the purpose of protecting cash flow. If management believes that a hedging contract will appropriately help manage cash flow then it may choose to enter into a commodity price hedge. The Group does not currently have any covenants under its current financing facilities to hedge future production. The Group had oil price sale financial hedges outstanding as at December 31, 2023, which are summarized as follows: Period Volume (barrels per day) Type Average Pricing January 1, 2024 – December 31, 2024 17,700 WTI/WCS Differential USD -15.03/bbl January 1, 2024 – December 31, 2024 6,250 WTI Sale Swap USD 80.94/bbl The Group had condensate financial hedges outstanding as at December 31, 2023, which are summarized as follows: Period Volume (barrels per day) Type Average Pricing January 1, 2024 – March 31, 2024 3,000 C5/WTI Differential USD -1.60/bbl 27 ===== SIDA 71 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 The Group had no gas price sale financial hedges outstanding as at December 31, 2023. The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had a positive fair value of USD 28,291 thousand as at December 31, 2023. The Group had electricity financial hedges outstanding as at December 31, 2023, which are summarized as follows: Period Volume (MW) Type Average Pricing October 1, 2025 – September 30, 2040 3 AESO CAD 75.00/MWh The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had a long term negative fair value of USD 202 thousand as at December 31, 2023. Currency Risk The Group’s policy on currency rate hedging is, in the case of currency exposure, to consider fixing the rate of exchange. The Group will take into account the currency exposure, current rates of exchange and market expectations in comparison to historic trends and volatility in making the decision to hedge. In 2023, IPC entered into foreign currency hedges in Canada to buy CAD 20 million per month at CAD 1.36 (sell USD) and in Malaysia to buy MYR 11.5 million per month at MYR 4.63 (sell USD) in respect of 2024, and to buy CAD 15 million per month at CAD 1.36 (sell USD) in respect of 2025, to partially meet forecast operational expenses in those countries. In respect of the forecast Blackrod development capital expenditure in Canada, IPC entered into further currency hedges to purchase a total CAD 556 million for the period January 2024 to December 2025 at an average rate of CAD 1.33 (sell USD). The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had a positive fair value of USD 12,934 thousand as at December 31, 2023. Interest Rate Risk Interest rate risk is the risk to earnings due to uncertain future interest rates on borrowings. The Group will take into account the level of external debt, current interest rates and market expectations in comparison to historic trends and volatility in making the decision to hedge. Credit Risk The Group may be exposed to third party credit risk through contractual arrangements with counterparties who buy the Group’s hydrocarbon products. The Group’s policy is to limit credit risk by only entering into oil and gas sales agreements with reputable and creditworthy oil and gas and trading companies. Where it is determined that there is a credit risk for oil and gas sales, the Group’s policy is to require credit enhancement from the purchaser. The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In addition, cash is to be held and transacted only through major banks. RISK FACTORS IPC is engaged in the exploration, development and production of oil and gas and its operations are subject to various risks and uncertainties which include but are not limited to those listed below. The risks and uncertainties below are not the only ones that the Group faces. Additional risks and uncertainties not presently known to the Group or that the Group currently considers immaterial may also impair the business and operations of the Group and cause the price of the IPC’s common shares to decline. If any of the following risks actually occur, the Group’s business may be harmed and the financial condition and results of operations may suffer significantly. See also “Cautionary Statement Regarding Forward-Looking Information” and “Reserves and Resources Advisory” below. Non Financial Risks Exploration, Development and Production Risks: Oil and gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Group depends on its ability to find, acquire, develop and commercially produce oil and gas reserves. Without the continual addition of new reserves, any existing reserves associated with the Group’s oil and gas assets at any particular time, and the production therefrom, will decline over time as such existing reserves are exploited. There is a risk that additional commercial quantities of oil and gas will not be discovered or acquired by the Group. Production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Future oil and gas development may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In 28 ===== SIDA 72 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. Production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Oil and gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, hydrocarbon releases and spills, each of which could result in substantial damage to oil and gas wells, production facilities, other property and the environment or personal injury. In accordance with industry practice, the Group will not fully insure against all of these risks, nor are all such risks insurable. The Group maintains liability insurance in an amount that it considers consistent with industry practice. Due to the nature of these risks, however, there is a risk that such liabilities could exceed policy limits, in which event the Group could incur significant costs. Volatility in Oil and Gas Commodity Prices and Price Differentials: The marketability and price of oil and gas that may be acquired or discovered by the Corporation is and will continue to be affected by numerous factors beyond its control. The Corporation’s ability to market its oil and gas may depend upon its ability to access space on pipelines that deliver oil and gas to commercial markets. The Corporation may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing and storage facilities, the capacity of such pipelines and facilities, and operational problems affecting such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and gas and many other aspects of the oil and gas business. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Corporation. These factors include economic conditions in Europe, Asia, the United States, Canada and elsewhere, the actions of OPEC and OPEC+, strategic petroleum reserve (SPR) management by the United States, the conflict in Ukraine, the impact of pandemics (including Covid19), governmental regulation, political instability in the Middle East and elsewhere, the foreign supply of oil and gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. Oil and gas prices have fluctuated widely during recent years and may continue to be volatile in the future. Any substantial and extended decline in the price of oil and gas would have an adverse effect on the carrying value of the reserves and resources, borrowing capacity, revenues, profitability and cash flows associated with the Group’s assets and may have a material adverse effect on the business, financial condition, results of operations and prospects associated with the Group’s assets. The Group’s financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials in Canada between the Group’s heavy crude oil (in particular the heavy crude oil differential) and quoted market prices. The market price for heavy crude oil and bitumen in Canada is generally lower than market prices for light oil, due principally to the higher costs associated with refining a barrel of heavy crude oil and higher transportation costs (diluent is required to be purchased and blended with heavy crude oil to transport on most pipelines). Heavy crude oil differentials are also influenced by other factors such as capacity and interruptions, refining demand and the quality of the oil produced, all of which are beyond the Group’s control. It is difficult to predict future price differentials and any increase in heavy crude oil differentials could have an adverse effect on the Group’s business, financial condition, results of operations and cash flows. In addition, there has not been, at times, sufficient pipeline capacity to export all Canadian crude oil and the availability of alternative transport capacity is more expensive and variable, therefore, the price for Canadian crude oil is very sensitive to pipeline and refinery outages. This has resulted in significantly lower prices being realized by Canadian producers compared with the WTI price and the Brent price for crude oil. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil and gas from Canada. There can be no certainty that current investment in pipelines will provide sufficient long-term export capacity or that currently operating systems will remain in service. There is also no certainty that short-term operational constraints on pipeline systems, arising from pipeline interruption, refinery outages and/or increased supply of crude oil, will not occur. In order to transport crude oil production in Canada to sales markets, the Group is required to meet certain pipeline specifications. Heavy crude oil and bitumen is usually blended with a lighter hydrocarbon (commonly referred to as diluent) to increase its flow characteristics. The cost of diluent is generally correlated to crude oil prices. A shortfall in the supply of diluent may cause its price to increase which would adversely affect the Group’s financial position and cash flow. Climate Change: Climate change issues are an important factor for the oil and gas industry. Transition Risks The Group’s facilities and operations, and the oil and gas that the Group markets, result in the emission of greenhouse gas (GHG) which makes the Group subject to GHG emissions legislation and regulation. Governments continue to evaluate and implement policy, legislation, and regulations focused on restricting GHG emissions commonly and promoting adaptation to climate change and the transition to a low-carbon economy. It is not possible to predict what measures governments may implement in this regard, nor is it possible to predict the requirements that such measures may impose or when such 29 ===== SIDA 73 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 measures may be implemented. Given the evolving nature of climate change policy and the control of GHG emissions and resulting requirements, including carbon taxes and carbon pricing schemes implemented by varying levels of government, it is expected that current and future climate change regulations will have the effect of increasing the Group’s operating expenses, and, in the long-term, potentially reducing the value of oil and gas assets. Regulatory climate change related risks arise from increased or amended environmental regulation. A breach of such regulations may result in the imposition of fines or issuance of clean up orders in respect of the Group or the Group’s assets, some of which may be material. Furthermore, management of the Corporation believes the political climate appears to favour new programs for environmental laws and regulation, particularly in relation to the reduction of, or limitations on, GHG emissions or emissions intensity. There is a risk that any such programs, laws or regulations, if proposed and enacted, may contain emission reduction targets which will require substantial capital investments to adapt processes in place or lead to financial penalties or charges as a result of the failure to meet such targets. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. Implementation of strategies by any level of government within the countries in which the Corporation operates, and whether to meet international agreed limits, or as otherwise determined, for reducing GHGs could have a material impact on the operations and financial condition of the Corporation. Increased scrutiny of applications for oil and gas licenses, permits and authorizations to develop assets and projects could lead to delay, limit or prevent future development of assets or affect the productivity of assets and the costs associated. In addition, concerns about climate change and public discussion that oil and gas operations may be associated with climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation, transportation and development of fossil fuels. Given the evolving nature of the debate related to climate change and the control of GHGs and resulting requirements, it is not possible to predict the impact on the Group and its operations and financial condition. Emission and carbon tax regulations in Canada federally and regionally are evolving and as these regulations are established or amended, they may have an impact on organizations involved in oil and gas production. Canada has taken steps to address climate change by establishing the Canadian Net-Zero Emissions Accountability Act that enshrines in law the Government of Canada’s commitment to achieve net-zero GHG emissions by 2050. In December 2023, the Government of Canada introduced draft regulations to cap oil and gas emissions by 2030 at levels 20% to 23% below 2019 levels (with the use of offsets) and 35% to 38% (without the use of offsets). The draft regulations are expected to be released in mid-2024 with final regulations in 2025. The regulations would be effective January 1, 2026. It is difficult to assess the overall impact these regulations will have on the Group at this time but it could result in increased costs to comply, delays in having projects approved and potentially a reduction in demand for oil from these regions, all of which could have a material negative impact on the Group’s business. The International Sustainability Standards Board (“ISSB”) was created on November 3, 2021 with the aim to develop globally consistent, comparable and reliable sustainability disclosure standards. On June 26, 2023, the ISSB issued IFRS S1 “General Requirements for Disclosure of Sustainability-related Financial Information” and IFRS S2 “Climate-related Disclosures”. The Corporation is actively evaluating the potential effects of the ISSB issued sustainability standards; however, at this time, the Corporation is not able to determine the impact on future financial statements, nor the potential costs to comply with these sustainability standards. Physical Risks Physical climate change related risks can be event-driven with increased severity of extreme weather events, such as cyclones, hurricanes, wildfires, droughts or floods, or long-term shifts in climate patterns with sustained higher temperatures, water stress or sea level rise. These physical risks may have financial and operational implications for the Group, such as direct damage to assets and indirect impacts from supply chain disruption to the delivery of goods and services. Certain of IPC’s oil and gas assets are in locations that are proximate to forests and rivers and a wildfire or flood may lead to significant downtime and/or damage. Reputational Risks: Reputational risks arise from the surge of societal pressure on the fossil fuel industry in relation to its contribution to global GHG emissions. Maintaining a positive reputation in the eyes of investors, regulators, communities, employees and the general public is an important aspect for the success of the Corporation. Negative impact on the industry and the Corporation’s reputation could result in the long-term delays in obtaining regulatory approvals, increased operating costs, lower shareholder confidence, or availability of insurance and financing. Oil and gas operations may be subject to public opposition. Such public opposition could result in higher costs, delays or even project cancellations due to increased pressure on governments and regulators by special interest groups including Indigenous groups, landowners, environmental groups and other organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support of governments, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses, and direct legal challenges, including the possibility of climate-related litigation. Project Risks: The Group is undertaking various projects, including Phase 1 of the Blackrod project. Project interruptions may delay expected revenues from operations. Significant project cost overruns could make a project uneconomic. IPC’s ability to execute projects depends upon numerous factors beyond its control, including: processing, pipeline and storage capacity, availability of water, electricity, gas, diluent and other operational supplies, effects of weather, availability of personnel and 30 ===== SIDA 74 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 equipment, unexpected cost increases, accidents, regulatory and third party approvals and commercial arrangements, stakeholder consultations (including Indigenous consultation) and regulatory changes (including carbon tax). As a result of these and other factors, the Group may be unable to execute projects on time, on budget, or at all. Inflationary Pressures and Costs: The Group’s operating costs could escalate and make operations unprofitable due to supply chain disruptions, inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, and additional government intervention. Labour costs, abandonment, reclamation, gas, electricity, water, diluent and chemicals are examples of some of the operating and other costs that are susceptible to significant fluctuation. The inability to manage costs may impact project returns and future development decisions, which could have an adverse effect on financial performance. The cost or availability of oil and gas field equipment may adversely affect IPC’s ability to undertake projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services. These materials and services may not be available when required at reasonable prices. A failure to secure the services and equipment necessary to operations or projects for the expected price, on the expected timeline, or at all, may have an adverse effect on financial performance. The Group’s financial performance is significantly affected by the cost of operating and the capital costs associated with its assets. Operating and capital costs are affected by a number of factors including, but not limited to inflationary price pressure, scheduling delays, failure to maintain quality construction standards and supply chain disruptions. Fluctuations in operating and capital costs could negatively impact the Group’s business, financial condition, results of operations, cash flows and value of its oil and gas reserves. Operational Risks Relating to Facilities and Pipelines: The pipelines and facilities associated with the Group’s assets, are exposed to operational risks that can lead to hydrocarbon releases, production interruptions and unplanned outages. Other operating risks relating to the facilities and pipelines associated with the Group’s assets include: the breakdown or failure of equipment; breakdown or malicious attacks on information systems or processes; the performance of equipment at levels below those originally intended; operator error; disputes and other issues with interconnected facilities; and catastrophic events such as natural disasters, fires, explosions, acts of terrorists and saboteurs and other similar events, many of which will be beyond the control of the Group. The occurrence or continuance of any of these or other operational events could curtail sales or production or materially increase the cost of operating the facilities and pipelines associated with the Group’s oil and gas assets and reduce revenues accordingly. Reductions in Demand for Oil and Gas: Increasing consumer demand for alternatives to oil and gas, conservation measures, alternative fuel requirements, and technological advances in fuel economy and renewable energy generation systems, could reduce the demand for oil and gas. Some jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and to encourage the use of renewable fuel alternatives, which could reduce the demand for oil and gas. Advancements in energy efficient products have a similar effect on the demand for oil and gas. The Corporation cannot predict the impact of changing demand for oil and gas products, and any major changes may have an adverse effect on IPC’s business, financial condition, results of operations and cash flow from operations by decreasing increasing costs, limiting access to capital and decreasing the value of oil and gas assets. Uncertainties Associated with Estimating Reserves and Resources Volumes: There are numerous uncertainties inherent in estimating quantities of oil and gas reserves and resources (contingent and prospective) and the future cash flows attributed to such reserves and resources. The cash flow information associated with reserves and resources set forth in this MD&A are estimates only. The actual production, revenues, taxes and development and operating expenditures with respect to the reserves and resources associated with the Group’s assets will vary from estimates thereof and such variations could be material. Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources In accordance with applicable securities laws, the Corporation and the Corporation’s independent reserves auditors have used forecast prices and costs in estimating the reserves, resources and future net cash flows as summarized herein. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and gas, curtailments or increases in consumption by oil and gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”. References to “prospective resources” do not constitute, and should be distinguished from, references to “contingent resources” and “reserves”. This MD&A contains estimates of the net present value of the future net revenue from IPC’s reserves and resources. The estimated values of future net revenue disclosed in this MD&A do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserves and resource evaluations will be attained and variances could be material. See also “Reserves and Resources Advisory” below. SAGD Recovery Process: : The Group has implemented a SAGD recovery process at the Onion Lake Thermal project and the Blackrod project. The SAGD recovery process requires a significant amount of gas or other fuels to produce steam for use in the recovery process. The amount of steam required in the production process can vary and impact costs significantly. The quality and performance of the reservoir can impact the timing, cost and levels of production using this technology. There can be no assurance that the Group’s operations will produce at the expected levels or on schedule. In addition, a significant amount of water is used in SAGD operations. Government regulations apply to access to and use of water. Any shortages in water supplies could lead to increased costs and have a material adverse effect on results of operation and financial condition. 31 ===== SIDA 75 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Hydraulic Fracturing: Hydraulic fracturing involves the injection of water, sand, and small amounts of additives under high pressure into tight rock formations that were previously unproductive to stimulate the production of oil and gas. Concerns about seismic activity, including earthquakes, caused by hydraulic fracturing has resulted in regulatory authorities implementing additional protocols for areas that are prone to seismic activity or completely banning hydraulic fracturing in other areas. Any new laws, regulations, or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase costs of compliance, as well as delay development of certain oil and gas resources. Restrictions or bans on hydraulic fracturing could result in restricting the economic recovery of oil and gas reserves. In addition, the Group may need to dispose of the fluids produced from oil and gas production operations, including produced water. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. Regulatory Approvals and Compliance and Changes in Legislation and the Regulatory Environment: Oil and gas operations (including exploration, development, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate or intervene with respect to exploration, production and abandonment activities, price, taxes (including carbon taxes), GHG emission restrictions, royalties and the export of oil and gas. The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for oil and gas and increase the costs associated with the Group’s oil and gas assets, any of which may have a material adverse effect on the business, financial condition, results of operations and prospects of the Group’s oil and gas assets. In order to conduct oil and gas operations, the Group will require regulatory permits, licences, registrations, approvals, authorizations and concessions from various governmental authorities. There is a risk that the permits, licences, registrations, approvals, authorizations and concessions currently granted to the Group will not be renewed or that the Group will be unable to obtain all of the permits, licences, registrations, approvals, authorizations and concessions that may be required to conduct operations that it may wish to undertake. The French government has enacted legislation to cease granting new petroleum exploration licences in France and to restrict the production of oil and gas under existing production licences in France from 2040. There is a risk that France could implement further legislative changes and that the licence regime in France could become more onerous. In Canada, the oil and gas regulatory authorities have implemented regulations regarding the ability to transfer leases, licences, permits, wells and facilities between parties. These authorities have increased the minimum abandonment liability rating of the buyer before they will accept a transfer of oil and gas assets. These regulations may make it difficult and costly for producers, such as IPC, to transfer or sell assets to other parties. Change in governments or policies in the countries in which the Group operates may have an impact on the decisions taken and regulations made by such governments on matters that may impact the oil and gas industry including the balance between economic development and environmental policy. The oil and gas industry has become an increasingly political topic, which has resulted in a rise in activism and criticism surrounding oil and gas development, particularly with respect to infrastructure projects. Protests, blockades and demonstrations have the potential to delay and disrupt the Group’s activities. Indigenous Land and Rights Claims: In Canada, Indigenous groups have filed claims in respect of their indigenous and treaty rights against the federal and certain provincial governments as well as private individuals and companies. Consultation delays, claims or objections related to Indigenous rights may disrupt or delay operations, new development or new project approvals on the Group’s properties. The Group is not aware of any claims made with respect to its properties or assets; however; if a claim arose and was successful, it may have a material adverse effect on the Group’s business, financial condition, results of operation and prospects. The majority of the Group’s interests at Onion Lake are situated on traditional reserve lands and are subject to the federal rules and regulations of Indian Oil and Gas Canada as well as of the Onion Lake Cree Nation of Saskatchewan/Alberta. There are risks associated with the management of the Group’s interests on these lands, including access and lease terms. The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain circumstances, accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of litigation. The fulfilment of the duty to consult Indigenous people and any associated accommodations may adversely affect the Group’s ability to, or increase the timeline to, obtain or renew, permits, leases, licences and other approvals, or to meet the terms and conditions of those approvals, or to advance project development, including Phase 1 of the Blackrod project. Change of Control under Licences: The licence areas associated with the Group’s oil and gas assets require government consent or compliance with regulations imposed by oil and gas regulatory authorities to effect a change of control of the owner or an assignment of the ownership interest in the licence area. There may also be contractual restrictions on assignment and change of control, including in the Suffield area of Canada where certain operations are conducted within a Canadian Forces Base under access agreements with Canadian federal government and the Alberta provincial government. Accordingly, should the Group propose to dispose of assets or if there is a change of control of the Corporation, consent may be required in order to remain in compliance with the applicable licences and concessions. The failure to obtain such consent may have a material adverse effect on the Corporation. Further, the requirement to obtain such consent may limit the ability of a third party to effect a change of control transaction with the Corporation. 32 ===== SIDA 76 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Failure to Realize Anticipated Benefits of Acquisitions and Dispositions: The Group may make acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as the Group’s ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Group. In addition, non-core assets may be periodically disposed of, so that the Group can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of the Group, if disposed of, could be expected to realize less than their carrying value on the financial statements of the Group. Reliance on Third Party Infrastructure: The Group delivers the products associated with the Group’s assets by gathering, processing and pipeline systems, most of which it does not own. The amount of oil and gas that the Group is able to produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems. The lack of availability of capacity in any of the gathering, processing and pipeline systems, and in particular the processing facilities, could ceased refining and result in the Corporation’s inability to realize the full economic potential of its production or in a reduction of the price offered for the Corporation’s production or increased operating or transportation costs. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm the Group’s business financial condition, results of operations, cash flows and future prospects. Credit Facilities and Bonds: The Group is, and may in the future become, party to credit facilities with international financial institutions. The Corporation has also issued bonds and may issue further bonds in the future. The terms of these facilities and bonds may contain operating and financial covenants and restrictions on the ability of the Group to, among other things, incur or lend additional debt, pay dividends and make restricted payments, encumber its assets, sell assets and enter into certain merger or consolidation transactions. The failure of the Group to comply with the covenants contained in these facilities and bonds could result in an event of default, which could, through acceleration of debt, enforcement of security or otherwise, materially and adversely affect the operating results and financial condition of the Group. In addition, the maximum amount that the Group is permitted to borrow under its credit facilities may be subject to periodic review by the lenders. The Group’s lenders generally review its oil and gas production and reserves, forecast oil and gas prices, general business environment and other factors to establish the amount which the Group is entitled to borrow. In the event the lenders decide to reduce the amount of credit available under the credit facilities, the Group may not have the ability to borrow funds under such facilities or may be required to repay all or a portion of the amounts owing thereunder. If the Group fails to comply with the covenants in these facilities and bonds, is unable to repay or refinance amounts owned at maturity or pay the debt service charges or otherwise commit an event of default, such as bankruptcy, it could result in the seizure and/or sale of the Group’s assets by the creditors. The proceeds from any sale of the Group’s assets would be applied to satisfy amounts owed to the secured creditors and then unsecured creditors. Only after the proceeds of that sale were applied towards the Group’s debt would the remainder, if any, be available for the benefit of shareholders. Credit Ratings: Credit ratings affect the Corporation’s ability to obtain short term and long term financing and the cost of such financing. A reduction in the current rating or a negative change in the rating outlook could adversely affect the cost of financing and access to sources of liquidity and capital. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant. Credit ratings are not recommendations to buy, sell or hold any of the Corporation’s securities. Competition for Resources and Markets: The international oil and gas industry is competitive in all its phases. The Group competes with numerous other organizations in the search for, and the acquisition of, oil and gas properties and in the marketing of oil and gas. The Corporation’s competitors include oil and gas companies that may have substantially greater financial resources, staff and facilities than those of the Corporation. The Corporation’s ability to increase its reserves and resources in the future depends not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory and development drilling. Competitive factors in the distribution and marketing of oil and gas include price and methods and reliability of delivery and storage. Competition may also be presented by alternate fuel sources and renewable energies. Marketing: A decline in the Group’s ability to market oil and gas production could have a material adverse effect on its production levels or on the price that the Group receives for production, which in turn may affect the financial condition of the Corporation and the market price of the common shares. IPC’s business depends in part upon the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities as well as, potentially, rail loading facilities and railcars. Applicable regulation of oil and gas production, processing and transportation, tax and energy policies, general economic conditions, and changes in supply and demand could adversely affect IPC’s ability to produce and market oil and gas. If market factors change and inhibit the marketing of production, overall production or realized prices may decline, which may affect the financial condition of the Corporation and the market price of the common shares. Hedging Strategies: From time to time, the Group may enter into agreements to receive fixed prices on its oil and gas production to offset the risk of revenue reductions if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, the Group will not benefit from such increases. Similarly, from time to time, the Group may enter into agreements to fix the exchange rate of certain currencies. However, if a currency declines in value compared to another currency, the Group may not benefit from the fluctuating exchange rate if an agreement has fixed such exchange rate. 33 ===== SIDA 77 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Fraud, Bribery and Corruption: The operations relating to the Group’s oil and gas assets are governed by the laws of many jurisdictions, which generally prohibit bribery and other forms of corruption. While the Corporation has implemented an anti- corruption compliance program across the Group, the Corporation cannot guarantee that the Group’s employees, officers, directors, agents, or business partners have not in the past or will not in the future engage in conduct undetected by the processes and procedures to be adopted by the Corporation and for which the Corporation might be held liable under applicable anti-corruption laws. Despite the Corporation’s compliance program and other related training initiatives, it is possible that the Corporation, or some of its subsidiaries, employees or contractors, could be subject to an investigation related to charges of bribery or corruption as a result of the unauthorized actions of its employees or contractors, which could result in significant corporate disruption, onerous penalties and reputational damage. Decommissioning, Abandonment and Reclamation Costs: The Group is responsible for compliance with all applicable laws, regulations and contractual requirements regarding the decommissioning, abandonment and reclamation of the Group’s assets at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of requirements at the time of decommissioning, abandonment and reclamation and the actual costs may exceed current estimates. Laws, regulations and contractual requirements with regard to abandonment and decommissioning may be implemented or amended in the future. Third Party Credit Risk: The Group may be exposed to third party credit risk through the contractual arrangements associated with the Group’s assets with its current or future joint venture partners, marketers of its petroleum and gas production, third party uses of its facilities and other parties. In the event such entities fail to meet their contractual obligations in respect of the Group’s assets, such failures may have a material adverse effect on the Group’s business, financial condition, results of operations and prospects. Repatriation of Earnings: Jurisdictions in which the Group operates may implement measures to facilitate management of foreign exchange risk. Such measures could restrict the Group’s ability to repatriate earning or other funds. Expiration and Renewal of Licences, Leases and Production Sharing Contracts: : Certain of the Group’s oil and gas assets are held in the form of licences, leases and production sharing contracts (PSCs). If the holder of the licence, lease or PSC or the operator of the licence, lease or PSC fails to meet the specific requirement of a licence, lease or PSC, including compliance with environmental, health and safety requirements, the licence, lease or PSC may terminate or expire. There is a risk that the obligations required to maintain each licence, lease or PSC will not be met. The termination or expiration of the licence, lease or PSC, or the working interests relating to a licence may have a material adverse effect on the business, financial condition, results of operations and prospects associated with the Group’s oil and gas assets. From time to time, the licences and leases may, in accordance with their terms, become due for renewal; there is a risk that these licences, leases and PSCs associated with the Group’s oil and gas assets will not be renewed by the relevant government authorities on terms that will be acceptable to the Corporation. There also can be significant delay in obtaining licence renewals which may already affect the operations associated with the Group’s oil and gas assets. Reliance on Third Party Operators: The Group has partners in some of the licence areas associated with the Group’s assets. In some cases, including in the Aquitaine Basin in France, the Group is not the operator of the licence and concession areas and must depend on the competence, expertise, judgment and financial resources (in addition to those of its own and, where relevant, other partnership and joint venture companies) of the partner operator and the operator’s compliance with the terms of the licences, leases and contractual arrangements. Mismanagement of licence areas by the Group’s partner operators or defaults by them in meeting required obligations may result in significant exploration, production or development delays, losses or increased costs to the Group. Litigation: In the normal course of the Group’s operations, it may become involved in, named as a party to, or be the subject of, various legal proceedings. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to the Group and as a result, could have a material adverse effect on the Group’s assets, liabilities, business, financial condition and results of operations. Terrorism and Sabotage: If any of the properties, wells or facilities comprising the Group’s assets is the subject of terrorist attack or sabotage, it may have a material adverse effect on the Group’s business, financial condition, results of operations, cash flows and future prospects. Information Security: The Group is dependent on its information systems and computer based programs. Failure, malfunction or security breaches by computer hackers and cyberterrorists of any such systems or programs may have a material adverse effect on the Group’s business and systems, potentially disrupting operations and affecting network assets and people’s privacy. The Group manages cyber security risk by ensuring appropriate technologies, processes and practices are effectively designed and implemented to help prevent, detect and respond to threats as they emerge and evolve. The Chief Operating Officer of the Corporation is principally responsible for overseeing cybersecurity risk management and for reporting such risks to other members of executive management and to the Board. The primary risks to the Group include, loss of data, destruction or corruption of data, compromising of confidential customer or employee information, leaked information, disruption of business, theft or extortion of funds, regulatory infractions, loss of competitive advantage and reputational damage. 34 ===== SIDA 78 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Insurance: Although the Group maintains insurance in accordance with industry standards to address certain risks related to oil and gas operations, such insurance has limitations on liability and may not be sufficient to cover the full extent of potential liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, the Group may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds available to IPC. The occurrence of a significant event that IPC is not fully insured against, or the insolvency of the insurer of such event, may have an adverse effect on IPC’s business, financial condition, results of operations and prospects. The Group’s insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, policy limits and/or deductibles for certain insurance policies can vary substantially. In some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Pandemics: The Covid-19 virus and the restrictions and disruptions related to it had a material effect on the world demand for, and prices of, oil and gas as well as the market price of the shares of oil and gas companies generally. There can be no assurance that these effects will not resume or that commodity prices will not decrease or remain volatile in the future due to Covid-19 or other pandemics. These factors are beyond the control of the Corporation, and it is difficult to assess how these, and other factors, will continue to affect the Corporation and the market price of IPC’s common shares. Potential Conflicts of Interest: Certain of the individuals who are directors of the Corporation are also directors of other oil and gas companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions. Key Personnel: IPC’s success is in part dependent upon management, leadership capabilities and the quality and competency of key personnel. If IPC is unable to retain key personnel and critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies, it could have an adverse effect on the Group’s financial condition, results of operations and prospects. Change in Investors: Some institutional and other investors have announced that they no longer are willing to fund or invest in oil and gas assets or companies, or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Corporation. Failing to implement the policies and practices, as requested by institutional investors, may result in such investors reducing their investment in the Corporation, or not investing in IPC at all. Significant Shareholder: Nemesia S.à.r.l., an investment company wholly owned by trusts whose settlor is the late Adolf H. Lundin (“Nemesia”), owns approximately 32 percent of the aggregate common shares of the Corporation. Nemesia’s holdings may allow it to significantly affect substantially all the actions taken by the shareholders of the Corporation, including the election of directors. As long as Nemesia maintains a significant interest in the Corporation, it is likely that Nemesia will exercise significant influence on the ability of the Corporation to, among other things, enter into a change in control transaction of the Corporation and may also discourage acquisition bids for the Corporation. There is a risk that the interests of Nemesia may not be aligned with the interests of other shareholders. Financial Risks Management Estimates and Assumptions: In preparing consolidated financial statements in conformity with IFRS, estimates and assumptions are used by management in determining the reported amounts of assets and liabilities, revenues and expenses recognized during the periods presented and disclosures of contingent assets and liabilities known to exist as of the date of the financial statements. These estimates and assumptions must be made because certain information that is used in the preparation of such financial statements is dependent on future events, cannot be calculated with a high degree of precision from data available, or is not capable of being readily calculated based on generally accepted methodologies. In some cases, these estimates are particularly difficult to determine and the Corporation must exercise significant judgment. Actual results for all estimates could differ materially from the estimates and assumptions used by the Corporation, which could have a material adverse effect on the Group’s business, financial condition, results of operations, cash flows and future prospects. Disclosure Controls and Procedures and Internal Controls over Financial Reporting: Effective disclosure controls and procedures and internal controls over financial reporting are necessary for the Corporation to provide reliable financial and other disclosures and to help prevent fraud. The Corporation cannot be certain that the procedures it undertakes to help ensure the reliability of its financial reports and other disclosures, including those imposed on it under Canadian securities laws, will ensure that it maintains adequate control over financial processes and reporting. Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm the Group’s results of operations or cause it to fail to meet its reporting obligations. If the Corporation or its independent auditor discover a material weakness, the disclosure of that fact, even if quickly remedied, could reduce the market’s confidence in the Corporation’s consolidated financial statements and harm the trading price of the common shares. Income Taxes: Income tax laws relating to the oil and gas industry, such as the treatment of resource taxation or dividends and the imposition of carbon taxes, may in the future be changed or interpreted in a manner that adversely affects the Group’s assets. Furthermore, there is a risk that the relevant tax authorities will not agree with management’s calculation of the income for tax purposes associated with the Group’s assets or that such tax authorities will change their administrative practices to the detriment of the Corporation. In the event of a successful reassessment of the Corporation’s income tax returns, such reassessment may have an impact on current and future taxes payable. 35 ===== SIDA 79 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 In 2022, the EU imposed tax on energy companies deriving income from operations in EU countries (“Solidarity Contribution”). The Solidarity Contribution was applicable to the Group in France for the 2022 fiscal year. Such tax could be extended or increased in the future, and similar taxes may be levied in other jurisdictions in which the Group operates or proposes to operate. Additional Funding Requirements: The Corporation’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From time to time, the Corporation may require additional financing in order to carry out its oil and gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Corporation’s revenues from its reserves decrease as a result of lower oil and gas prices or otherwise, it will affect the Corporation’s ability to expend the necessary capital to replace its reserves or to maintain its production. If the Corporation’s funds from operations is not sufficient to satisfy its capital expenditure requirements, there is a risk that debt or equity financing will be unavailable to meet these requirements or, if available, will be on terms unacceptable to the Corporation. Continued uncertainty in domestic and international credit markets could materially affect the Corporation’s ability to access sufficient capital for its capital expenditures and acquisitions, and as a result, may have a material adverse effect on the Corporation’s ability to execute its business strategy and on its business, financial condition, results of operations and prospects and also negatively impact the market price of the common shares. Variations in Foreign Exchange Rates and Interest Rates: World oil and gas prices are quoted in United States dollars and are therefore affected by exchange rates, which will fluctuate over time. Future exchange rates could accordingly impact the future value of the Corporation’s reserves and resources as determined by independent reserve auditors. To the extent that the Corporation engages in risk management activities related to foreign exchange rates, there will be a credit risk associated with counterparties of the Corporation. An increase in interest rates could result in a significant increase in the amount the Corporation pays to service any debt that it may incur, which could negatively impact the market price of the common shares. Issuance of Further Debt: From time to time, the Corporation may enter into transactions to acquire assets or the shares of other organizations. These transactions may be financed in whole or in part with debt, which may create debt or increase the Corporation’s then-existing debt levels above industry standards for oil and gas companies of similar size. Depending on future exploration and development plans, the Corporation may require additional equity and/or debt financing that may not be available or, if available, may not be available on favorable terms. The level of the indebtedness that the Corporation may have from time to time could impair the Corporation’s ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise. Common Share Price Volatility: The market price for common shares may be volatile and subject to wide fluctuations in response to numerous factors, many of which are beyond the Corporation’s control, including the following: • Actual or anticipated fluctuations in the Corporation’s results of operations; • Recommendations by securities research analysts; • Changes in the economic performance or market valuations of other companies that investors deem comparable to the Corporation; • The loss of executive officers and other key personnel of the Corporation; • Issuances or perceived issuances of additional common shares; • Significant acquisitions or business combinations, strategic partnerships, joint ventures or capital; • Commitments by or involving the Corporation or its competitors; and • Trends, concerns, technological or competitive developments, regulatory changes and other related issues in the Corporation’s business segments or target markets. Financial markets can experience significant price and volume fluctuations that may particularly affect the market prices of equity securities of companies and that may be unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of the common shares may decline even if the Corporation’s operating results, underlying asset values or prospects have not changed. These factors, as well as other related factors, may cause decreases in asset values, which may result in impairment losses. DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING Disclosure Controls and Procedures Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation. Management, under the supervision of the Chief Executive Officer and the Chief Financial Officer, is responsible for the design and operation of disclosure controls and procedures. Internal Controls over Financial Reporting Management is also responsible for the design of the Group’s internal controls over financial reporting in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. However, due to inherent limitations, internal control over financial reporting may not prevent or detect all misstatements and fraud. There have been no material changes to the Groups internal control over financial reporting during the year ended December 31, 2023, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial reporting. 36 ===== SIDA 80 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 Control Framework Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control – Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This MD&A contains statements and information which 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. Actual results may differ materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this MD&A, unless otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. All statements other than statements of historical fact may be forward-looking statements. 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“. Forward-looking statements include, but are not limited to, statements with respect to: • 2024 production range, operating costs, operating cash flow, free cash flow, and capital and decommissioning expenditure estimates; • Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business plans and assumptions regarding the business environment, which are subject to change; • IPC’s financial and operational flexibility to continue to react to recent events and navigate the Corporation through periods of volatile commodity prices; • The ability to fully fund future expenditures from cash flows and current borrowing capacity; • IPC’s intention and ability to continue to implement its strategies to build long-term shareholder value; • The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth; • The continued facility uptime and reservoir performance in IPC’s areas of operation; • Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing, regulatory approvals, third party commercial arrangements, breakeven oil prices and net present values; • Future development potential of the Suffield, Brooks, Ferguson and Mooney operations, including the timing and success of future oil and gas drilling and optimization programs; • Current and future operations and production performance at Onion Lake Thermal; • The potential improvement in the Canadian oil egress situation and IPC’s ability to benefit from any such improvements; • The ability of IPC to achieve and maintain current and forecast production in France and Malaysia; • The intention and ability of IPC to acquire further common shares under the NCIB, including the timing of any such purchases; • The return of value to IPC’s shareholders as a result of the NCIB; • The ability of IPC to implement further shareholder distributions in addition to the NCIB; • IPC’s ability to implement its GHG emissions intensity and climate strategies and to achieve its net GHG emissions intensity reduction targets; • Estimates of reserves and contingent resources; • The ability to generate free cash flows and use that cash to repay debt; • IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the Corporation; • IPC’s ability to maintain operations, production and business in light of any future pandemics and the restrictions and disruptions related thereto, including risks related to production delays and interruptions, changes in laws and regulations and reliance on third party operators and infrastructure; • IPC’s ability to identify and complete future acquisitions; and • Future drilling and other exploration and development activities. Statements relating to “reserves“ and “contingent resources“ are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management. See also “Reserves and Resources Advisory“. The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve and contingent resource volumes; operating costs; the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the benefits of acquisitions; 37 ===== SIDA 81 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally; the availability and cost of financing, labour and services; and the ability to market crude oil, natural gas and natural gas liquids successfully. 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. These include, but are not limited to: • General global economic, market and business conditions; • The risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; • Delays or changes in plans with respect to exploration or development projects or capital expenditures; • The uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses; • Health, safety and environmental risks; • Commodity price fluctuations; • Interest rate and exchange rate fluctuations; • Marketing and transportation; • Loss of markets; • Environmental and climate-related risks; • Competition; • Incorrect assessment of the value of acquisitions; • Failure to complete or realize the anticipated benefits of acquisitions or dispositions; • The ability to access sufficient capital from internal and external sources; • Failure to obtain required regulatory and other approvals; and • Changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations. Readers are cautioned that the foregoing list of factors is not exhaustive. See also “Risk and Uncertainties” Estimated FCF generation is based on IPC’s current business plans over the periods of 2024 to 2028 and 2029 to 2033. Assumptions include average net production of approximately 55 Mboepd over the period of 2024 to 2028, average net production of approximately 65 Mboepd over the period of 2029 to 2033, average Brent oil prices of USD 75 to 95 per boe 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 current business plans and assumptions, and the business environment, are subject to change. Actual results may differ materially from forward-looking estimates and forecasts. Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the Financial Statements, the Corporation’s material change report (MCR) dated February 6, 2024, the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2022, (See “Cautionary Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk Factors”) and other reports on file with applicable securities regulatory authorities, including previous financial reports, management’s discussion and analysis and material change reports, which may be accessed through the SEDAR+ website (www.sedarplus.ca) or IPC’s website (www.international-petroleum.com). Management of IPC approved the production, operating costs, operating cash flow, capital and decommissioning expenditures and free cash flow guidance and estimates contained herein as of the date of this MD&A release. The purpose of these guidance and estimates is to assist readers in understanding IPC’s expected and targeted financial results, and this information may not be appropriate for other purposes. RESERVES AND RESOURCES ADVISORY This MD&A contains references to estimates of gross and net reserves and resources attributed to the Corporation’s oil and gas assets. Gross reserves/resources are the working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests. Net reserves/resources are the working interest (operating or non-operating) share after deduction of royalty obligations, plus royalty interests in reserves/resources, and in respect of PSCs in Malaysia, adjusted for cost and profit oil. Unless otherwise indicated, reserves/resource volumes are presented on a gross basis. Reserve 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, 2023, 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, 2023 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, 2023, 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, 2023 price forecasts. 38 ===== SIDA 82 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 The price forecasts used in the Sproule and ERCE reports, are available on the website of Sproule (sproule. com) and are contained in the MCR. These price forecasts are as at December 31, 2023 and may not be reflective of current and future forecast commodity prices. The reserve life index (RLI) is calculated by dividing the 2P reserves of 468 MMboe as at December 31, 2023, by the mid-point of the 2024 CMD production guidance of 46,000 to 48,000 boepd. The product types comprising the 2P reserves described in this MD&A are contained in the MCR. See also “Supplemental Information regarding Product Types” below. Light, medium and heavy crude oil reserves/resources disclosed in this MD&A include solution gas and other by-products. “2P reserves“ means proved plus probable reserves. “Proved reserves“ are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. “Probable reserves“ are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Each of the reserves categories reported (proved and probable) may be divided into developed and undeveloped categories. “Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. “Developed producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. “Developed non-producing reserves” are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. “Undeveloped reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or characterized by their economic status. There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. Contingent resources are further classified based on project maturity. The project maturity subclasses include development pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources are classified as either development on hold or development unclarified. Development on hold is defined as a contingent resource where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator. Development unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until commercial considerations can be clearly defined. Chance of development is the probability of a project being commercially viable. References to “unrisked“ contingent resources volumes means that the reported volumes of contingent resources have not been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook guidance for contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies required for the re-classification of the contingent resources as reserves being resolved. Therefore, unrisked reported volumes of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such resources. The contingent resources reported in this MD&A are estimates only. The estimates are based upon a number of factors and assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this MD&A. 39 ===== SIDA 83 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 2P reserves and contingent resources included in the reports prepared by Sproule and ERCE in respect of IPC’s oil and gas assets in Canada, France and Malaysia have been aggregated by IPC. Estimates of reserves, resources and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves, resources and future net revenue for all properties, due to aggregation. This MD&A contains estimates of the net present value of the future net revenue from IPC’s reserves and contingent resources. The estimated values of future net revenue disclosed in this MD&A do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve and resources evaluations will be attained and variances could be material. The reserves and resources information and data provided in this MD&A present only a portion of the disclosure required under NI 51-101. All of the required information will be contained in the Corporation’s Annual Information Form for the year ended December 31, 2023, which will be filed on SEDAR+ (accessible at www.sedarplus.ca) on or before April 1, 2024. Further information with respect to IPC’s reserves, contingent resources and estimates of future net revenue is disclosed in the MCR available under IPC’s profile on www.sedarplus.ca and on IPC’s website at www.international-petroleum.com. References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel (bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value. Supplemental Information regarding Product Types The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily production figures provided in this document: Heavy Crude Oil (Mbopd) Light and Medium Crude Oil (Mbopd) Conventional Natural Gas (per day) Total (Mboepd) Three months ended December 31, 2023 25.7 6.6 103.8 MMcf (17.3 Mboe) 49.6 December 31, 2022 22.6 10.3 98.1 MMcf (16.4 Mboe) 49.2 Year ended December 31, 2023 December 31, 2023 25.8 8.1 102.8MMcf (17.1 Mboe) 51.1 December 31, 2022 22.6 9.6 98.1MMcf (16.4 Mboe) 48.6 This document also makes reference to IPC’s forecast average daily production of 46,000 to 48,000 boepd for 2024. IPC estimates that approximately 51% of that production will be comprised of heavy oil, approximately 15% will be comprised of light and medium crude oil and approximately 34% will be comprised of conventional natural gas. 40 ===== SIDA 84 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 OTHER SUPPLEMENTARY INFORMATION Abbreviations CAD Canadian dollar MCAD Million Canadian dollar EUR Euro USD US dollar MUSD Million US dollar MYR Malaysian Ringgit FPSO Floating Production Storage and Offloading (facility) Oil related terms and measurements AECO The daily average benchmark price for natural gas at the AECO hub in southeast Alberta AESO Alberta Electric System Operator API An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale ASP Alkaline surfactant polymer (an EOR process) ARV Argus WCS Houston (a reference price for the cost of transporting WCS quality oil from Alberta to Houston) bbl Barrel (1 barrel = 159 litres) boe1 Barrels of oil equivalents boepd Barrels of oil equivalents per day bopd Barrels of oil per day Bcf Billion cubic feet Bscf Billion standard cubic feet C5 Condensate CO2e Carbon dioxide equivalents, including carbon dioxide, methane and nitrous oxide Empress The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border EOR Enhanced Oil Recovery GJ Gigajoules Mbbl Thousand barrels MMbbl Million barrels Mboe Thousand barrels of oil equivalents Mboepd Thousand barrels of oil equivalents per day Mbopd Thousand barrels of oil per day MMboe Million barrels of oil equivalents MMbtu Million British thermal units Mcf Thousand cubic feet Mcfpd Thousand cubic feet per day MMcf Million cubic feet MW Mega watt MWh Mega watt per hour NGL Natural gas liquid SAGD Steam assisted gravity drainage (a thermal recovery process) WTI West Texas Intermediate (a light oil reference price) WCS Western Canadian Select (a heavy oil reference price) 1 All volume references to boe are calculated on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) unless otherwise indicated. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. BOEs may be misleading, particularly if used in isolation. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. 41 ===== SIDA 85 ===== Management’s Discussion and Analysis For the three months ended and year ended December 31, 2023 DIRECTORS C. Ashley Heppenstall Director, Chair London, England William Lundin Director, President and Chief Executive Officer Coppet, Switzerland Chris Bruijnzeels Director Abcoude, The Netherlands Donald K. Charter Director Toronto, Ontario, Canada Lukas (Harry) H. Lundin Director Toronto, Ontario, Canada Emily Moore Director Toronto, Ontario, Canada Mike Nicholson Director Monaco Deborah Starkman Director Toronto, Ontario, Canada OFFICERS Christophe Nerguararian Chief Financial Officer Geneva, Switzerland Nicki Duncan Chief Operating Officer Geneva, Switzerland Jeffrey Fountain General Counsel and Corporate Secretary Geneva, Switzerland Rebecca Gordon Senior Vice President Corporate Planning and Investor Relations Geneva, Switzerland Chris Hogue Senior Vice President, Canada Calgary, Alberta, Canada Ryan Adair Vice President Asset Management and Corporate Planning, Canada Calgary, Alberta, Canada Curtis White Vice President Commercial, Canada Calgary, Alberta, Canada MEDIA AND INVESTOR RELATIONS Robert Eriksson Stockholm, Sweden CORPORATE OFFICE Suite 2000 – 885 West Georgia Street Vancouver, British Columbia V6C 3E8 Canada Telephone: +1 604 689 7842 Website: www.international-petroleum.com OPERATIONS OFFICE 5 Chemin de la Pallanterie 1222 Vésenaz Switzerland Telephone: +41 22 595 10 50 E-mail: info@international-petroleum.com REGISTERED AND RECORDS OFFICE Suite 3500 - 1133 Melville Street Vancouver, British Columbia V6E 4E5 Canada INDEPENDENT AUDITORS PricewaterhouseCoopers SA, Switzerland TRANSFER AGENT Computershare Trust Company of Canada Calgary, Alberta, and Toronto, Ontario STOCK EXCHANGE LISTINGS Toronto Stock Exchange and NASDAQ Stockholm Trading Symbol: IPCO 42 ===== SIDA 86 ===== Corporate Office International Petroleum Corp Suite 2000 885 West Georgia Street Vancouver, BC V6C 3E8, Canada Tel: +1 604 689 7842 E-mail: info@international-petroleum.com Web: international-petroleum.com□