===== SIDA 1 ===== Q3 International Petroleum Corporation Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 ===== SIDA 2 ===== 2 Contents Interim Condensed Consolidated Statement of Operations 3 Interim Condensed Consolidated Statement of Comprehensive Income 4 Interim Condensed Consolidated Balance Sheet 5 Interim Condensed Consolidated Statement of Cash Flow 6 Interim Condensed Consolidated Statement of Changes in Equity 7 Notes to the Interim Condensed Consolidated Financial Statements 8 Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 3 ===== 3 Interim Condensed Consolidated Statement of Operations For the three and nine months ended September 30, 2023 and 2022, UNAUDITED Three months ended September 30 Nine months ended September 30 USD Thousands Note 2023 2022 2023 2022 Revenue 2 257,366 299,361 655,446 874,683 Cost of sales Production costs 3 (130,765) (122,655) (364,889) (351,355) Depletion and decommissioning costs 7 (31,687) (31,939) (71,488) (91,721) Depreciation of other tangible fixed assets 9 (1,509) (2,991) (6,503) (8,092) Exploration and business development costs 24 (1,287) (2,007) (2,217) Gross profit 2 93,429 140,489 210,559 421,298 Sale of assets 7 11,912 – 11,912 – General, administration and depreciation expenses (3,952) (2,784) (12,304) (10,700) Profit before financial items 101,389 137,705 210,167 410,598 Finance income 4 5,833 1,641 14,238 2,269 Finance costs 5 (10,090) (10,866) (30,465) (33,398) Net financial items (4,257) (9,225) (16,227) (31,129) Profit before tax 97,132 128,480 193,940 379,469 Income tax expense 6 (25,451) (37,977) (50,671) (102,927) Net result 71,681 90,503 143,269 276,542 Net result attributable to: Shareholders of the Parent Company 71,673 90,491 143,247 276,493 Non-controlling interest 8 12 22 49 71,681 90,503 143,269 276,542 Earnings per share – USD 1 15 0.56 0.63 1.08 1.83 Earnings per share fully diluted – USD1 15 0.54 0.62 1.05 1.80 1 Based on net result attributable to shareholders of the Parent Company See accompanying notes to the interim condensed consolidated financial statements ===== SIDA 4 ===== 4 Interim Condensed Consolidated Statement of Comprehensive Income For the three and nine months ended September 30, 2023 and 2022, UNAUDITED Three months ended September 30 Nine months ended September 30 USD Thousands Note 2023 2022 2023 2022 Net result 71,681 90,503 143,269 276,542 Other comprehensive income Items that may be reclassified to profit or loss: Reclassification of hedging (gains) / losses to profit or loss 2 (1,854) (8,396) (11,969) 460 Gains / (losses) on cash flow hedges (2,274) 7,778 6,339 11,071 Income tax relating to these items 1,044 296 1,389 (2,709) Currency translation adjustments (11,811) (44,871) 5,100 (62,642) Total comprehensive income 56,786 45,310 144,128 222,722 Total comprehensive income attributable to: Shareholders of the Parent Company 56,781 45,306 144,114 222,691 Non-controlling interest 5 4 14 31 56,786 45,310 144,128 222,722 See accompanying notes to the interim condensed consolidated financial statements ===== SIDA 5 ===== 5 Interim Condensed Consolidated Balance Sheet As at September 30, 2023 and December 31, 2022, UNAUDITED USD Thousands Note September 30, 2023 December 31, 2022 ASSETS Non-current assets Oil and gas properties 7 1,150,136 963,375 Other tangible fixed assets 9 26,697 33,374 Right-of-use assets 3,009 1,217 Deferred tax assets 6 1,686 1,960 Derivative instruments 19 2,466 – Other assets 10 42,857 41,125 Total non-current assets 1,226,851 1,041,051 Current assets Inventories 11 20,478 15,958 Trade and other receivables 12 151,370 123,609 Derivative instruments 19 12,078 11,741 Current tax receivables 486 18 Cash and cash equivalents 13 542,608 487,240 Total current assets 727,020 638,566 TOTAL ASSETS 1,953,871 1,679,617 LIABILITIES Non-current liabilities Financial liabilities 16 6,086 8,711 Bonds 16 433,845 295,440 Lease liabilities 2,192 507 Provisions 17 234,620 203,389 Deferred tax liabilities 6 69,840 56,334 Derivative instruments 19 2,149 – Total non-current liabilities 748,732 564,381 Current liabilities Trade and other payables 18 158,214 118,726 Financial liabilities 16 3,425 3,431 Derivative instruments 19 7,394 1,155 Current tax liabilities 1,458 17,793 Lease liabilities 881 752 Provisions 17 8,641 8,048 Total current liabilities 180,013 149,905 EQUITY Shareholders’ equity 1,024,952 965,140 Non-controlling interest 174 191 Net shareholders’ equity 1,025,126 965,331 TOTAL EQUITY AND LIABILITIES 1,953,871 1,679,617 Approved by the Board of Directors (Signed) C. Ashley Heppenstall (Signed) Mike Nicholson Director Director See accompanying notes to the interim condensed consolidated financial statements ===== SIDA 6 ===== 6 Interim Condensed Consolidated Statement of Cash Flow For the three and nine months ended September 30, 2023 and 2022, UNAUDITED Three months ended September 30 Nine months ended September 30 USD Thousands Note 2023 2022 2023 2022 Cash flow from operating activities Net result 71,681 90,503 143,269 276,542 Adjustments for non-cash related items: Depletion, depreciation and amortization 7,9 33,601 35,336 79,180 101,014 Gain on sale of assets 7 (11,912) – (11,912) – Income tax 6 25,451 37,977 50,671 102,927 Amortization of capitalized financing fees 5 339 307 1,120 2,949 Foreign currency exchange 4,5 (854) 1,902 1,493 5,945 Interest expense 5 5,787 5,686 16,591 15,201 Interest income 4 (4,979) (1,632) (14,238) (2,236) Unwinding of asset retirement obligation discount 5 3,479 2,667 10,021 8,156 Share-based costs 1,907 1,494 6,847 5,493 Other 214 577 629 987 Cash flow generated from operations (before working capital adjustments and income taxes) 124,714 174,817 283,671 516,978 Changes in working capital (3,527) (9,028) (10,171) (37,404) Decommissioning costs paid 17 (2,755) (962) (7,126) (4,724) Other payments 17 – (1,420) (864) (2,018) Income taxes received / (paid) (7,043) (1,478) (33,117) (10,367) Interest received 5,948 1,613 13,713 2,214 Interest paid (10,985) (10,927) (21,946) (11,425) Net cash flow from operating activities 106,352 152,615 224,160 453,254 Cash flow used in investing activities Investment in oil and gas properties 7 (76,844) (46,729) (183,904) (114,870) Acquisition of Cor4 net of cash acquired 8 – – (59,419) – Disposal of assets 7 13,736 – 13,736 – Investment in other tangible fixed assets 9 (65) (29) (482) (117) Net cash (outflow) from investing activities (63,173) (46,758) (230,069) (114,987) Cash flow from financing activities Borrowings / (Repayments) 16 (894) 1,598 (2,630) (96,798) Net Bonds issuance proceeds 16 137,550 – 137,550 300,000 Paid financing fees 16 – – (507) (5,583) Financing of Substantial Issuer Bid (“SIB”) – (1,237) – (100,887) Repurchase of own shares 14 (12,138) (46,906) (72,293) (67,935) Other payments (283) (173) (728) (523) Net cash (outflow) from financing activities 124,235 (46,718) 61,392 28,274 Change in cash and cash equivalents 167,414 59,139 55,483 366,541 Cash and cash equivalents at the beginning of the period 374,177 327,860 487,240 18,810 Currency exchange difference in cash and cash equivalents 1,017 13,490 (115) 15,138 Cash and cash equivalents at the end of the period 542,608 400,489 542,608 400,489 See accompanying notes to the interim condensed consolidated financial statements ===== SIDA 7 ===== 7 Interim Condensed Consolidated Statement of Changes in Equity For the three and nine months ended September 30, 2023 and 2022, UNAUDITED 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 – 143,247 – – – – 143,247 22 143,269 Acquisition of Cor41 – – – – 881 – 881 – 881 Cash flow hedge – – – – (5,122) – (5,122) – (5,122) Currency translation difference – – 5,251 (189) 46 – 5,108 (8) 5,100 Total comprehensive income – 143,247 5,251 (189) (4,195) – 144,114 14 144,128 Dividend distribution – – – – – – – (31) (31) Repurchase of own shares2 (72,293) – – – – – (72,293) – (72,293) Share based costs – – – 19,805 – – 19,805 – 19,805 Share based payments3 (13,415) – – (18,399) – – (31,814) – (31,814) Balance at September 30, 2023 253,011 779,142 (26,041) 12,566 3,763 2,511 1,024,952 174 1,025,126 1 See Note 8 2 See Note 14 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 – 276,493 – – – – 276,493 49 276,542 Cash flow hedge – – – – 8,822 – 8,822 – 8,822 Currency translation difference – – (61,256) (802) (566) – (62,624) (18) (62,642) Total comprehensive income – 276,493 (61,256) (802) 8,256 – 222,691 31 222,722 Repurchase of own shares1 (67,935) – – – – – (67,935) – (67,935) Substantial Issuer Bid (“SIB”)1 (100,887) – – – – – (100,887) – (100,887) Share based payments (8,514) – – 433 – – (8,081) – (8,081) Balance at September 30, 2022 351,428 574,705 (49,965) 9,331 9,130 (1,455) 893,174 188 893,362 1 See Note 14 See accompanying notes to the interim condensed consolidated financial statements. ===== SIDA 8 ===== 8 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED 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 unaudited interim condensed consolidated financial statements have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The financial statements should be read in conjunction with IPC’s annual consolidated financial statements for the year ended December 31, 2022, which have been prepared in accordance with IFRS as issued by the IASB. These unaudited interim consolidated financial statements are presented in United States Dollars (USD), which is the Group’s presentation and functional currency. The unaudited interim 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. The unaudited interim condensed consolidated financial statements have been approved by the Board of Directors of IPC and authorized for issuance on October 31, 2023. The unaudited interim condensed consolidated financial statements have been prepared following the same accounting policies and methods of application as those in the Group’s audited annual consolidated financial statements for the year ended December 31, 2022. C. Going concern The unaudited interim condensed consolidated financial statements for the nine months ended September 30, 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 nine months ended September 30, 2023, the Group applied the amended accounting standards, interpretations and annual improvement points that are effective as of January 1, 2023. ===== SIDA 9 ===== 9 2. 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, exploration and evaluation costs and gross profit. 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 7. Three months ended September 30, 2023 USD Thousands Canada Malaysia France Other Total Crude oil 201,513 46,148 19,318 – 266,979 NGLs 377 – – – 377 Gas 16,705 – – – 16,705 Net sales of oil and gas 218,595 46,148 19,318 – 284,061 Change in under/over lift position – – 4,349 – 4,349 Royalties (31,973) – (1,239) – (33,212) Hedging settlement 1,854 – – – 1,854 Other operating revenue – – 229 85 314 Revenue 188,476 46,148 22,657 85 257,366 Operating costs (62,796) (11,062) (9,004) – (82,862) Cost of blending (39,836) – – – (39,836) Change in inventory position 315 (8,478) 96 – (8,067) Depletion and decommissioning costs (24,593) (3,438) (3,656) – (31,687) Depreciation of other tangible fixed assets – (1,509) – – (1,509) Exploration and business development costs – – – 24 24 Gross profit/(loss) 61,566 21,661 10,093 109 93,429 Three months ended September 30, 2022 USD Thousands Canada Malaysia France Other Total Crude oil 187,625 71,138 21,884 – 280,647 NGLs 170 – – – 170 Gas 37,397 – – – 37,397 Net sales of oil and gas 225,192 71,138 21,884 – 318,214 Change in under/over lift position – – 534 – 534 Royalties (26,527) – (1,409) – (27,936) Hedging settlement 8,396 – – – 8,396 Other operating revenue 10 – 143 – 153 Revenue 207,071 71,138 21,152 – 299,361 Operating costs (53,405) (9,249) (8,349) – (71,003) Cost of blending (42,358) – – – (42,358) Change in inventory position (968) (8,488) 162 – (9,294) Depletion and decommissioning costs (19,453) (9,618) (2,868) – (31,939) Depreciation of other tangible fixed assets – (2,991) – – (2,991) Exploration and business development costs – – – (1,287) (1,287) Gross profit/(loss) 90,887 40,792 10,097 (1,287) 140,489 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 10 ===== 10 Nine months ended September 30, 2023 USD Thousands Canada Malaysia France Other Total Crude oil 521,383 85,924 52,476 – 659,783 NGLs 845 – – – 845 Gas 52,564 – – – 52,564 Net sales of oil and gas 574,792 85,924 52,476 – 713,192 Change in under/over lift position – – 8,842 – 8,842 Royalties (75,713) – (3,575) – (79,288) Hedging settlement 11,969 – – – 11,969 Other operating revenue 7 – 639 85 731 Revenue 511,055 85,924 58,382 85 655,446 Operating costs (187,476) (26,509) (24,609) – (238,594) Cost of blending (128,523) – – – (128,523) Change in inventory position 269 2,141 (182) – 2,228 Depletion and decommissioning costs1 (46,285) (14,818) (10,385) – (71,488) Depreciation of other tangible fixed assets – (6,503) – – (6,503) Exploration and business development costs (834) – (9) (1,164) (2,007) Gross profit/(loss) 148,206 40,235 23,197 (1,079) 210,559 1 In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program. Nine months ended September 30, 2022 USD Thousands Canada Malaysia France Other Total Crude oil 624,517 139,782 83,284 – 847,583 NGLs 632 – – – 632 Gas 118,842 – – – 118,842 Net sales of oil and gas 743,991 139,782 83,284 – 967,057 Change in under/over lift position – – (911) – (911) Royalties (86,861) – (4,796) – (91,657) Hedging settlement (460) – – – (460) Other operating revenue 111 – 543 – 654 Revenue 656,781 139,782 78,120 – 874,683 Operating costs (160,806) (25,657) (26,688) – (213,151) Cost of blending (142,638) – – – (142,638) Change in inventory position 1,465 2,195 774 – 4,434 Depletion and decommissioning costs (56,230) (26,020) (9,471) – (91,721) Depreciation of other tangible fixed assets – (8,092) – – (8,092) Exploration and business development costs 97 – – (2,314) (2,217) Gross profit/(loss) 298,669 82,208 42,735 (2,314) 421,298 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 11 ===== 11 3. PRODUCTION COSTS Three months ended September 30 Nine months ended September 30 USD Thousands 2023 2022 2023 2022 Cost of operations 70,887 61,167 205,039 181,924 Tariff and transportation expenses 10,643 8,542 29,701 27,063 Direct production taxes 1,332 1,294 3,854 4,164 Operating costs 82,862 71,003 238,594 213,151 Cost of blending1 39,836 42,358 128,523 142,638 Change in inventory position 8,067 9,294 (2,228) (4,434) Total production costs 130,765 122,655 364,889 351,355 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. 4. FINANCE INCOME Three months ended September 30 Nine months ended September 30 USD Thousands 2023 2022 2023 2022 Foreign exchange gain, net 854 – – – Interest income 4,979 1,632 14,238 2,236 Other financial income – 9 – 33 Total finance income 5,833 1,641 14,238 2,269 5. FINANCE COSTS Three months ended September 30 Nine months ended September 30 USD Thousands 2023 2022 2023 2022 Foreign exchange loss, net – 1,902 1,493 5,945 Interest expense 5,787 5,686 16,591 15,201 Unwinding of asset retirement obligation discount 3,479 2,667 10,021 8,156 Amortization of loan fees 59 28 282 2,205 Amortization of bond fees 280 279 838 744 Loan commitment fees 189 93 463 447 Other financial costs 296 211 777 700 Total finance costs 10,090 10,866 30,465 33,398 6. INCOME TAX Three months ended September 30 Nine months ended September 30 USD Thousands 2023 2022 2023 2022 Current tax (7,459) (5,052) (16,045) (14,049) Deferred tax (17,992) (32,925) (34,626) (88,878) Total tax recovery / (expense) (25,451) (37,977) (50,671) (102,927) Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 12 ===== 12 Specification of deferred tax assets and tax liabilities1 USD Thousands September 30, 2023 December 31, 2022 Unused tax loss carry forward 29,405 32,815 Other 5,621 5,841 Deferred tax assets 35,026 38,656 Accelerated allowances 101,872 90,400 Other 1,308 2,630 Deferred tax liabilities 103,180 93,030 Deferred taxes, net (68,154) (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. 7. OIL AND GAS PROPERTIES USD Thousands September 30, 2023 December 31, 2022 Exploration and Evaluation Assets – 4,764 Property, Plant and Equipment 1,150,136 958,611 Oil and gas properties 1,150,136 963,375 Exploration and Evaluation Assets USD Thousands Canada Malaysia France Total Cost January 1, 2023 – – 4,764 4,764 Additions – – 9 9 Write-off – – (9) (9) Reclassification – – (4,731) (4,731) Currency translation adjustments – – (33) (33) Net book value September 30, 2023 – – – – USD Thousands Canada Malaysia France Total Cost January 1, 2022 12,751 181 5,105 18,037 Additions 1 (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 are being offset against capitalized costs of Exploration and Evaluation Assets. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 13 ===== 13 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 8 72,242 – – 72,242 Additions 166,864 1,803 15,228 183,895 Disposals1 (7,720) – – (7,720) Reclassification – – 4,731 4,731 Currency translation adjustments 10,125 – (3,005) 7,120 September 30, 2023 1,331,300 568,409 416,191 2,315,900 Accumulated depletion January 1, 2023 (323,273) (485,034) (288,714) (1,097,021) Depletion charge for the period (70,340) (14,818) (10,385) (95,543) Disposals1 4,329 – – 4,329 Other2 22,857 – – 22,857 Currency translation adjustments (2,538) – 2,152 (386) September 30, 2023 (368,965) (499,852) (296,947) (1,165,764) Net book value September 30, 2023 962,335 68,557 119,244 1,150,136 1 In Canada, includes the disposal of non-core properties, John Lake area, with an effective date of August 1, 2023 for gross proceeds of CAD 19.4 million (USD 14.4 million) and a net accounting gain on disposal of CAD 16.0 million (USD 11.9 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 Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 14 ===== 14 8. 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. Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during the first nine months of 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%. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 15 ===== 15 9. OTHER TANGIBLE FIXED ASSETS USD Thousands FPSO Other Total Cost January 1, 2023 204,853 9,779 214,632 Additions – 482 482 Disposals – (453) (453) Currency translation adjustments (144) (8) (152) September 30, 2023 204,709 9,800 214,509 Accumulated depreciation January 1, 2023 (173,311) (7,947) (181,258) Depreciation charge for the period (6,503) (513) (7,016) Disposals – 453 453 Currency translation adjustments – 9 9 September 30, 2023 (179,814) (7,998) (187,812) Net book value September 30, 2023 24,895 1,802 26,697 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 to August 2025, being the original Bertam field production sharing contract (PSC) expiry date, before 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 Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 16 ===== 16 10. OTHER NON-CURRENT ASSETS USD Thousands September 30, 2023 December 31, 2022 Long-term receivables 28,115 28,154 Financial assets 14,742 12,971 42,857 41,125 Long-term receivables represent cash payments made to an asset retirement obligation fund and financial assets include secured amounts of USD 7.7 million transferred for the future asset retirement obligation, in respect of the Bertam field, Malaysia. 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 17.) 11. INVENTORIES USD Thousands September 30, 2023 December 31, 2022 Hydrocarbon stocks 11,689 8,988 Well supplies and operational spares 8,789 6,970 20,478 15,958 12. TRADE AND OTHER RECEIVABLES USD Thousands September 30, 2023 December 31, 2022 Trade receivables 123,023 112,696 Underlift 9,240 599 Joint operations debtors 1,334 982 Prepaid expenses and accrued income 14,672 6,585 Other 3,101 2,747 151,370 123,609 13. CASH AND CASH EQUIVALENTS Cash and cash equivalents include only cash at hand or held in bank accounts. As at September 30, 2023, an amount of USD 5.2 million is restricted. 14. SHARE CAPITAL The Corporation’s issued common share capital is as follows: Number of shares Balance at January 1, 2022 155,198,105 Cancellation following the Substantial Issuer Bid (8,258,064) Cancellation of repurchased common shares (10,112,042) Balance at December 31, 2022 136,827,999 Cancellation of repurchased common shares (7,638,779) Balance at September 30, 2023 129,189,220 The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 17 ===== 17 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. As at September 30, 2023, following the cancellation during the first nine months of 2023 of a further 7,638,779 common shares repurchased under the NCIB, IPC had a total of 129,189,220 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. 15. 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. Three months ended September 30 Nine months ended September 30 2023 2022 2023 2022 Net result attributable to shareholders of the Parent Company, USD 71,672,906 90,491,024 143,247,365 276,492,795 Weighted average number of shares for the period 128,875,283 142,656,482 133,066,728 150,986,635 Earnings per share, USD 0.56 0.63 1.08 1.83 Weighted average diluted number of shares for the period 131,745,540 145,501,486 135,936,985 153,831,639 Earnings per share fully diluted, USD 0.54 0.62 1.05 1.80 16. FINANCIAL LIABILITIES USD Thousands September 30, 2023 December 31, 2022 Bank loans 9,511 12,142 Bonds 439,517 300,000 Capitalized financing fees (5,672) (4,560) 443,356 307,582 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 September 30, 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. No cash amounts were drawn under the Canadian RCF as at September 30, 2023. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 18 ===== 18 The bond repayment obligations as at September 30, 2023, are classified as non-current as there are no mandatory repayments within the next twelve months. As at September 30, 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 September 30, 2023 was USD 10 million (EUR 9 million). An amount of USD 3.4 million (EUR 3.2 million) drawn under the France Facility as at September 30, 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 September 30, 2023. 17. 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 8 29,885 – – – 29,885 Additions – – – 497 497 Unwinding of asset retirement obligation discount 10,021 – – – 10,021 Disposals 1 (1,749) – – – (1,749) Payments (7,126) (557) – (307) (7,990) Other 2 (1,262) – – – (1,262) Reclassification 3 1,781 – – – 1,781 Currency translation adjustments 834 (186) – (7) 641 September 30, 2023 238,633 2,661 306 1,661 243,261 Non-current 231,056 1,597 306 1,661 234,620 Current 7,577 1,064 – – 8,641 Total 238,633 2,661 306 1,661 243,261 1 In Canada, includes the disposal of non-core properties, John Lake area, with an effective date of August 1, 2023 for gross proceeds of CAD 19.4 million (USD 14.4 million) and a net accounting gain on disposal of CAD 16.0 million (USD 11.9 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 10). 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 10). Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 19 ===== 19 The farm-in obligation relates to future payments for historic costs on Block PM307 in Malaysia payable on reaching certain Bertam field production milestones. 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. 18. TRADE AND OTHER PAYABLES USD Thousands September 30, 2023 December 31, 2022 Trade payables 43,809 20,547 Joint operations creditors 20,246 14,348 Accrued expenses 86,772 78,206 Other 7,387 5,625 158,214 118,726 19. FINANCIAL ASSETS AND LIABILITIES Financial assets and liabilities by category The accounting policies for financial instruments have been applied to the line items below: September 30, 2023 USD Thousands Total Financial assets at amortized cost Fair value recognized in profit or loss (FVTPL) Derivatives used for hedging Other assets1 42,857 42,857 – – Derivative instruments 14,544 – – 14,544 Joint operation debtors 1,334 1,334 – – Other current receivables2 135,850 126,610 9,240 – Cash and cash equivalents 542,608 542,608 – – Financial assets 737,193 713,409 9,240 14,544 1 See Note 10 2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments. September 30, 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 439,931 439,931 – – Current financial liabilities 3,425 3,425 – – Derivative instruments 9,543 – – 9,543 Joint operation creditors 20,246 20,246 – – Other current liabilities 139,426 139,426 – – Financial liabilities 612,571 603,028 – 9,543 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 20 ===== 20 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 41,125 41,125 – – 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 657,148 644,808 599 11,741 1 See Note 10 2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments. 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: September 30, 2023 USD Thousands Level 1 Level 2 Level 3 Other current receivables 9,240 – – Derivative instruments – current – 12,078 – Derivative instruments – non-current – 2,466 – Financial assets 9,240 14,544 – Derivative instruments – current – 7,394 – Derivative instruments – non-current – 1,996 153 Financial liabilities – 9,390 153 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 – Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED ===== SIDA 21 ===== 21 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED The Group had gas price sale financial hedges outstanding as at September 30, 2023, which are summarized as follows: Period Volume (Gigajoules (GJ) per day) Type Average Pricing October 1, 2023 – October 31, 2023 35,0001 AECO Swap CAD 3.95/GJ 1 Equivalent to 33,700 Mcf per day at CAD 4.10/Mcf. The Group had oil price sale financial hedges outstanding as at September 30, 2023 which are summarized as follows: Period Volume (barrels per day) Type Average Pricing October 1, 2023 - December 31, 2023 12,000 WCS/ARV Differential USD -10.08/bbl January 1, 2024 - December 31, 2024 17,700 WCS/WTI Differential USD -15.03/bbl January 1, 2024 - December 31, 2024 2,500 WTI Sale Swap USD 81.16/bbl The Group had condensate financial hedges outstanding as at September 30, 2023 which are summarized as follows: Period Volume (barrels per day) Type Average Pricing October 31, 2023 – March 31, 2024 3,000 C5/WTI Differential USD -1.60/bbl The Group had electricity financial hedges outstanding as at September 30, 2023 which are summarized as follows: Period Volume (MW) Type Pricing October 1, 2025 - September 1, 2040 3 AESO CAD 75.00/MWh In October 2022, IPC entered into currency hedge swaps for 2023 to buy CAD 15 million per month, sell USD at an average exchange rate of 1.36 and to buy EUR 3 million per month, sell USD at an average exchange rate of 1.00. In June 2023, IPC entered into currency hedge swaps for the second half of 2023 to buy MYR 13 million per month, sell USD at an average exchange rate of 4.54. These financial currency hedges are to partially fund forecast operational expenditures in those currencies in Canada, France and Malaysia respectively. In respect of the forecast Blackrod development capital expenditure in Canada, IPC had foreign currency hedge swaps outstanding at September 30, 2023 summarized as follows: Period Total amount to Buy Type Average CAD/USD Rate October 2023 – March 2025 Buy MCAD 436 Forward swap 1.31 All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. 20. CONTRACTUAL OBLIGATIONS AND COMMITMENTS In Canada, an oil pipeline from the Onion Lake Thermal field to a gathering system has been built by a third party for the exclusive use of IPC. The initial investment in the pipeline was met by the pipeline owner and is to be recovered through an agreed tariff charged to IPC. IPC has committed to a firm transportation service for 15 years from commencement of service in April 2022, with total remaining tariffs committed as shown in the table below: 2023 2024 2025 2026 2027 Thereafter Transportation service (MCAD) 6.9 28.0 28.4 29.0 28.2 275.2 In Malaysia, IPC has an obligation to make payments towards historic costs on Block PM307 payable on the Bertam field for every 1 MMboe gross that the field produces above 10 MMboe gross. The estimated liability based on current 2P reserves and which is capped at cumulative production of 27.5 MMboe gross, has been provided for in the Group’s Balance Sheet (see Note 17). ===== SIDA 22 ===== 22 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2023 and 2022, UNAUDITED 21. RELATED PARTIES During Q3 2023, the Group paid USD 273 thousand to the Lundin Foundation in respect of sustainability advisory services provided to the Group. During Q3 2023, the Group paid USD 685 thousand to Orrön Energy (formerly Lundin Energy) in respect of office space rental for 2023. During Q3 2023, Orrön Energy paid USD 641 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. 22. SUBSEQUENT EVENTS In October 2023, IPC completed the disposal of a non-core property, Fishing Lake, in Canada for a consideration of CAD 3.5 million, effective August 1, 2023. In October 2023, IPC entered into additional WTI oil swap hedges for 2024 fixing the WTI price at USD 80.80 for an additional 3,750 bopd. Together with volumes hedged previously, this results into a total of 6,250 bopd hedged for the whole year 2024 at a WTI price of USD 80.94. In October 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 4.64 (sell USD) 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 120 million for the period January 2024 to December 2025 at an average rate of CAD 1.36 (sell USD). No other events have occurred since September 30, 2023, that are expected to have a substantial effect on this report. ===== SIDA 23 ===== 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 24 ===== Q3 International Petroleum Corporation Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 ===== SIDA 25 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 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 International Financial Reporting Standards (IFRS) and do not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF , FCF , EBITDA, operating costs and net debt/ net cash that may be used by other public companies. Management believes that OCF , FCF , EBITDA, operating costs and net debt/net cash are useful supplemental measures that may assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS measure is presented in this MD&A. See “Non-IFRS Measures” on page 22. Forward-Looking Statements Certain statements contained in this MD&A constitute “forward-looking statements” or “forward-looking information” (within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements”) relate to future events, including the Corporation’s future performance, business prospects or opportunities. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, guidance, budgets, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“, “continue“, “estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, “might“, “should“, “believe“, “budget“ and similar expressions) are not statements of historical fact and may be “forward-looking statements“. Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. For additional information underlying forward-looking statements, refer to the “Cautionary Statement Regarding Forward-Looking Information” on page 27. Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada (other than the assets acquired in the Cor4 acquisition) are effective as of December 31, 2022, 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, 2022, price forecasts. Reserve estimates and estimates of future net revenue in respect of IPC’s oil and gas assets acquired in the Cor4 acquisition are effective as of December 31, 2022, and have been audited by GLJ Ltd. (GLJ), an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 31, 2022, 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, 2022, 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, 2022, 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 5 • Business Overview 5 • Operations Overview 9 FINANCIAL REVIEW 12 • Financial Results 12 • Capital Expenditure 20 • Financial Position and Liquidity 21 • Non-IFRS Measures 22 • Off-Balance Sheet Arrangements 24 • Outstanding Share Data 24 • Contractual Obligations and Commitments 25 • Critical Accounting Policies and Estimates 25 • Transactions with Related Parties 25 • Financial Risk Management 25 RISK AND UNCERTAINTIES 27 DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING 27 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 27 RESERVES AND RESOURCES ADVISORY 29 OTHER SUPPLEMENTARY INFORMATION 31 2 ===== SIDA 26 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 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 October 31, 2023 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 unaudited interim condensed consolidated financial statements and accompanying notes for the three and nine months ended September 30, 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 International Financial Reporting 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: September 30, 2023 September 30, 2022 December 31, 2022 Average Period end Average Period end Average Year end 1 EUR equals USD 1.0835 1.0594 1.0650 0.9748 1.0539 1.0666 1 USD equals CAD 1.3454 1.3429 1.2828 1.3747 1.3015 1.3538 1 USD equals MYR 4.5134 4.6952 4.3422 4.6370 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, reserves, 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 27 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 HIGHLIGHTS Q3 2023 Business Highlights • Strong quarterly average net production of approximately 50,200 barrels of oil equivalent (boe) per day (boepd) for the third quarter of 2023 (55% heavy crude oil, 14% light and medium crude oil and 31% natural gas).(1) • Blackrod Phase 1 development progressing on schedule and budget. • Disposal of non-core properties in Canada for MUSD 17 (0.6 MMboe of 2P reserves; approximately 400 bopd of average current production). (1)(2) • Successfully completed planned maintenance turnaround at the Bertam Field in Malaysia on scope, schedule and budget. • 1.31 million common shares purchased and cancelled during Q3 2023 under IPC’s normal course issuer bid (NCIB); annual program 90% complete. (1)(2) • IPC plans to seek TSX approval for the renewal of the NCIB for a further twelve months from December 2023 to December 2024, with IPC’s current intention to fully complete the renewed program. • Successfully completed USD 150 million tap issue under IPC’s existing 7.25% senior unsecured bond framework. • IPC succession plan sees William Lundin assume the role of President and CEO from January 1, 2024 as Mike Nicholson retires from executive management; Mike to continue as a Director of IPC and William to join the Board as a new Director. Q3 2023 Financial Highlights • Operating costs per boe of USD 17.9 for Q3 2023.(1)(3) • Operating cash flow (OCF) generation for Q3 2023 amounted to MUSD 119. (1)(3) • Capital and decommissioning expenditures of MUSD 80 for Q3 2023. (1) • Free cash flow (FCF) generation for Q3 2023 amounted to MUSD 35 (MUSD 103 pre Blackrod funding). (1)(3) • Net cash of MUSD 83 as at September 30, 2023. (3) • Net result of MUSD 72 for Q3 2023. Reserves and Resources • Total 2P reserves as at December 31, 2022 of 487 million boe (MMboe), with a reserves life index (RLI) of 27 years. (1)(2) • Contingent resources (best estimate, unrisked) as at December 31, 2022 of 1,162 MMboe.(1)(2) 2023 Annual Guidance • Full year 2023 average net production forecast unchanged at greater than 50,000 boepd. (1) • Full year 2023 operating costs guidance forecast remains unchanged at USD 17.5 to 18.0 per boe. (1)(3) • Full year 2023 OCF guidance tightened to between MUSD 340 to 365 (assuming Brent USD 80 to 90 per barrel for the remainder of 2023) from previous guidance of MUSD 320 to 390 (assuming Brent USD 75 to 90 per barrel). (1)(3) • Full year 2023 capital and decommissioning expenditures forecast reduced from MUSD 365 to MUSD 330. (1) • Full year 2023 FCF forecast range tightened to between MUSD -15 to 5 (assuming Brent USD 80 to 90 per barrel for the remainder of 2023) from previous guidance of MUSD -65 to 5 (assuming Brent USD 75 to 90 per barrel), after taking into account MUSD 240 of proposed 2023 Blackrod capital expenditures. (1)(3)(4) Three months ended September 30 Nine months ended September 30 USD Thousands 2023 2022 2023 2022 Revenue 257,366 299,361 655,446 874,683 Gross profit 93,429 140,489 210,559 421,298 Net result 71,681 90,503 143,269 276,542 Operating cash flow(3) 119,142 171,654 279,414 509,279 Free cash flow(3) 34,703 116,681 67,379 364,954 EBITDA(3) 123,054 174,328 284,334 513,829 Net Cash(3) 83,097 88,615 83,097 88,615 4 ===== SIDA 28 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 OPERATIONS REVIEW Business Overview Oil prices rebounded during the third quarter with Brent prices averaging USD 87 per barrel compared with USD 78 per barrel during the second quarter. The strength we have seen in physical markets shone through, with recessionary fears on the back of higher interest rates taking a back seat during the quarter. However, more recent talk of higher interest rates for longer by the Federal Reserve Bank, led to oil prices retreating from a push towards USD 100 per barrel in late September, back towards USD 85 per barrel in early October. Looking forward, the decision by OPEC+ to extend their ‘voluntary cuts’ through the end of 2023, could set the stage for a large deficit and further draws on already below average inventories during the fourth quarter. Inventory levels now sit more than 100 million barrels below the five-year average levels. Heightened tensions, with the tragic outbreak of war in the Middle East, are exacerbating the situation and will no doubt lead to increased pricing volatility going forward. IPC has decided to commence the hedging of its benchmark oil price exposure for 2024. Around 25% of 2024 West Texas Intermediate (WTI) exposure has been hedged at a price of USD 81 per barrel. The third quarter 2023 WTI to Western Canadian Select (WCS) crude price differentials averaged around USD 13 per barrel, a USD 2 per barrel improvement on the second quarter. The fundamental outlook for 2024 differentials remains positive with the expansion of the Trans Mountain (TMX) pipeline (590,000 barrels per day of extra capacity linking Edmonton to the port of Vancouver) as well as a reduction in Mexican heavy oil exports to the US (due to domestic refinery capacity increases by more than 200,000 barrels per day). That being said, a possible delay in start-up of the TMX pipeline from the first quarter to the second quarter of 2024 as a result of a tunnelling issue, has seen 2024 WTI - WCS differential widen to more than USD 17 per barrel. IPC took the decision to hedge 75% of our WCS differential exposure prior to news of the TMX pipeline potential delay, when market prices were more favourable averaging USD 15 per barrel. Gas market prices held stable during the third quarter at around CAD 2.50 per Mcf. During the third quarter, IPC continued to benefit from the AECO gas price hedges that were put in place when gas prices were much stronger in late 2022: 33.7 MMcf per day at CAD 4.10 per Mcf from April to October 2023, which represents approximately 50% of our net long exposure. Third Quarter 2023 Highlights and Full Year 2023 Guidance During the third quarter of 2023, our assets delivered average net production of 50,200 boepd, above our high-end guidance for the third quarter in succession. Above high-end guidance performance in Canada was partially offset by some downtime from two production wells in Malaysia that are scheduled for workover intervention activity. This work is expected to be concluded by January 2024. Given the very strong performance during the first nine months of 2023 averaging around 51,600 boepd, full year 2023 average net production guidance remains unchanged at greater than 50,000 boepd, above our original high end guidance. (1) Our operating costs per boe for the third quarter of 2023 were USD 17.9, in line with our latest guidance. Full year 2023 operating costs per boe guidance of USD 17.5 to 18.0 per boe remains unchanged. (1)(3) Operating cash flow (OCF) generation for the third quarter of 2023 was USD 119 million, towards the high end of guidance, driven by strong production and tighter WTI to WCS differentials. Full year 2023 OCF guidance of USD 320 to 390 million (assuming Brent USD 75 to 90 per barrel) is tightened to USD 340 to 365 million (assuming Brent USD 80 to 90 per barrel for the remainder of 2023). (1)(3) Full year 2023 capital and decommissioning expenditure forecast of USD 365 million is revised down to USD 330 million largely driven by rephasing of certain Blackrod capital expenditure from 2023 into 2024 and some additions relating to the workover of two wells in Malaysia. (1) Free cash flow (FCF) generation was USD 35 million (USD 103 million pre Blackrod funding) during the third quarter of 2023. Full year 2023 FCF guidance of USD -65 to 5 million (assumed Brent USD 75 to 90 per barrel) is tightened to USD -15 to 5 million (assuming Brent USD 80 to 90 per barrel for the remainder of 2023). (1)(3)(4) IPC’s transformational growth program is estimated to generate FCF post growth investment of between USD 2.6 and 4.4 billion over the next ten years assuming average Brent oil prices between USD 75 to 95 per barrel. This represents more than 2 to 3 times IPC’s current market capitalisation. (1)(3)(4) During the third quarter of 2023, IPC successfully completed a tap issue of USD 150 million under IPC’s existing 7.25% senior unsecured bond framework issued at 7% discount to par value and therefore with net proceeds amounting to USD 139.5 million to further strengthen IPC’s cash position. Following the tap issue, IPC has USD 450 million of senior unsecured bonds outstanding with maturity in February 2027. 5 ===== SIDA 29 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 IPC’s net cash position of USD 64 million as at June 30, 2023 was increased to USD 83 million as at September 30, 2023.(3) Gross cash on the balance sheet as at September 30, 2023 amounts to USD 543 million providing a significant war chest to pursue our three strategic pillars of returning value to stakeholders, pursuing value adding M&A and focusing on organic growth. Furthermore, during Q3 2023, IPC increased its Canadian Revolving Credit Facility (RCF) from CAD 150 million to CAD 165 million. The RCF remains undrawn as at October 31, 2023. Phase 1 Blackrod Project Following the successful completion of FEED studies and the continued strong production performance from well pair three during 2022, IPC took the decision in Q1 2023 to advance the development of Phase 1 of the Blackrod project. Development capital expenditure to first oil is estimated at approximately USD 850 million. First oil of the Phase 1 development is estimated to be in late 2026, with forecast production of 30,000 bopd by 2028. The breakeven oil price estimated by IPC assuming a 10% discount rate is a WTI price of approximately USD 59 per barrel. Using the December 31, 2022 price forecasts of our independent qualified reserves evaluator, Sproule Associates Limited (Sproule), the net present value as at that date, at a 10% discount rate (after tax), of Phase 1 of the Blackrod project is USD 807 million. IPC intends to fund the Phase 1 development with cash on hand and forecast FCF generated by our operations. (1)(2) During the third quarter, the Phase 1 development activities have progressed according to plan. The engineering, procurement and construction (EPC) contract for the major Phase 1 central processing facility was signed in Q2 2023 and project work continued to progress during Q3 2023 with cost levels and schedule in line with expectation. In addition, IPC has locked in more than 70% of the CAD/USD exposure through a combination of hedging and contractual arrangements to give greater certainty to the USD funding requirement for the Phase 1 project costs. M&A During the first nine months of 2023, IPC continued the successful integration of the acquired Brooks assets into the Group following completion of the Cor4 acquisition in March 2023. Four wells were successfully drilled and brought on production from the Ellerslie fairway since the beginning of the year and we plan to drill another four wells on this exciting play in 2023, two more than originally planned. (1)(2) During the third quarter, IPC agreed to dispose of a small package of non-core production and land assets in the John Lake and Fishing Lake areas in Canada. Total proceeds from the disposal amounted to USD 17 million. Current production associated with the assets was around 365 bopd. 2P reserves and NPV10 value as of January 1, 2023 were 0.6 MMboe and USD 7.7 million respectively. The John Lake disposal closed in Q3 2023 and Fishing Lake early October 2023. (1)(2) Capital Allocation Framework Normal Course Issuer Bid In Q4 2022, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 9.3 million common shares over the twelve-month period to early December 2023. By the end of September 2023, IPC purchased and cancelled 8.4 million common shares under the NCIB. The average price of common shares purchased under the renewed NCIB during the period of December 2022 to September 2023 was SEK 101 / CAD 13.00 per share. IPC expects to complete the current NCIB program of 9.3 million common shares during Q4 2023. As at September 30, 2023, IPC had a total of 129,189,220 common shares issued and outstanding, with no common shares held in treasury. Capital Allocation Plans IPC’s capital allocation framework consists of distributing to shareholders a minimum of 40% of the Free Cash Flow generated by the business, provided that IPC’s net debt to EBITDA ratio is at or below 1 time. (3) These shareholder distributions are planned to be implemented by continued share repurchases under the NCIB as well as the consideration by IPC of other forms of shareholder distributions, subject to further applicable regulatory and corporate approvals. The IPC Board of Directors has approved, subject to acceptance by the TSX, the renewal of IPC’s NCIB for a further twelve months from December 2023 to December 2024. We expect that the renewed NCIB program will permit IPC to purchase on the TSX and/or Nasdaq Stockholm, and cancel, up to a further 8.3 million common shares, representing approximately 6.5% of the total outstanding common shares (or 10% of IPC’s “public float” under applicable TSX rules) following completion of the current NCIB program. Despite the level of capital investment expected for 2024, in particular related to the Blackrod Phase 1 project, and notwithstanding the capital allocation framework described above, IPC’s current intention is to complete the renewed NCIB program during 2024. We continue to believe that materially growing our 2P reserves, production and asset value whilst reducing our share count is a winning combination for shareholders. 6 ===== SIDA 30 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Environmental, Social and Governance (ESG) Performance Alongside the publication of the second quarter 2023 financial report, IPC released its fourth annual Sustainability Report and first standalone TCFD Report. 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 our operations. During the third quarter of 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. During Q1 2023, IPC extended its commitment to remain at 2025 levels of 20 kg CO2/boe through to the end of 2027. IPC Succession Plan After nineteen years with the Lundin Group, Mike Nicholson, President and CEO has informed the IPC Board of his intention to step down from his executive position at the end of 2023. William Lundin, currently Chief Operating Officer of IPC (COO), will assume the role of President and CEO from January 1, 2024 and Nicki Duncan, currently Group Operations Lead, will assume the role of COO. The Board intends to increase the size of the Board to seven members and William will join as a new Director as of January 1, 2024, with Mike remaining on the Board. Mike Nicholson said: “IPC is generating robust cash flow from the base business, the balance sheet is stronger than ever, and our Blackrod growth project is progressing well, on schedule and budget. I firmly believe that our production and cash flow growth, coupled with continued share buy backs and opportunistic M&A, will continue to generate superior shareholder returns in the years ahead. I am excited to be handing over the reins to William Lundin, current COO of IPC, with such a bright future ahead of the company. Having had the pleasure of working side by side with Will for more than three years in his current role, I have been deeply impressed with his knowledge of value creation within the resource industry and the vision that we share to set the pace for our industry peers and to continue to outperform the competition. Will has amassed a vast amount of experience from working in field operations at Onion Lake Thermal and project management in the Canadian business, executive management within IPC, and strategic oversight in his various board positions across the Lundin Group. I know that Lukas Lundin would be very proud of Will’s progression to CEO. The COO role will be assumed by Nicki Duncan, currently IPC’s Group Operations Lead. I am delighted to remain as a Board Director and in this capacity look forward to my continued involvement in the amazing IPC success story.” William Lundin said: “It has been a privilege working alongside Mike. His contributions to IPC and Lundin Energy have been invaluable and we look forward to his continued support as a Director of IPC. I take great pride in having the opportunity to represent IPC as President and CEO and look forward in continuing to maximise value alongside a highly talented team. Our strategy remains intact to deliver shareholder returns, grow organically, and opportunistically seek accretive acquisitions. With a strong balance sheet, proven portfolio of high-quality producing assets delivering robust free cashflow to the business combined with transformational production growth to come from our Blackrod asset, the outlook for IPC is extremely bright.” 7 ===== SIDA 31 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Notes: (1) See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory” below. See also the annual information form for the year ended December 31, 2022 (AIF) available on IPC’s website at www.international- petroleum.com and under IPC’s profile on SEDAR+ at www.sedarplus.ca. IPC completed the acquisition of 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 and forecast operational and financial information included in the MD&A, including production, reserves, 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 AIF . 2P reserves as at December 31, 2022 of 487 MMboe includes 471 MMboe attributable to IPC’s oil and gas assets and 15.9 MMboe attributable to the oil and gas assets acquired in the Cor4 acquisition. (3) Non-IFRS measure, see “Non-IFRS Measures” below. (4) Estimated FCF generation is based on IPC’s current business plans over the periods of 2023 to 2027 and 2028 to 2032, including net cash of USD 175 million as at December 31, 2022 less the Cor4 acquisition consideration of USD 62 million. Assumptions include average net production of approximately 50 Mboepd over the period of 2023 to 2027, average net production of approximately 65 Mboepd over the period of 2028 to 2032, 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 AIF . IPC’s market capitalization is at close on October 27, 2023 (USD 1,330 million based on 114.85 SEK/share, 129.2 million IPC shares outstanding and exchange rate of 11.15 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. 8 ===== SIDA 32 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Operations Overview Reserves and Resources The 2P reserves attributable to IPC’s oil and gas assets are 487 MMboe as at December 31, 2022, as certified by independent third party reserve auditors. The proved plus probable reserve life index (RLI) as at December 31, 2022, is approximately 27 years. Best estimate contingent resources as at December 31, 2022, are 1,162 MMboe (unrisked). See “Reserves and Resources Advisory” below. IPC’s proved plus probable reserves increased by 80% at year end 2022 relative to year end 2021. The substantial increase in 2P reserve additions for the company was largely attributed to the sanctioning of the transformational Blackrod Phase 1 development project and further complemented by a conventional asset acquisition adjacent to the Suffield property in Southern Alberta and by securing a 10 year PSC extension at the PM307 block in Malaysia. During the third quarter in Canada, the Blackrod Phase 1 development progressed in accordance with plan. Initial construction camps have been installed and site preparations are underway to allow for drilling and equipment delivery beginning in 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. In the Suffield area, four out of the six planned Ellerslie wells have been drilled by end Q3 2023. Given the strong performance and robust pricing environment, IPC has elected to increase drilling activity by adding two more production wells to the 2023 program. At Onion Lake Thermal, the newly developed production sustaining Pad L has come on stream ahead of schedule. In France, planned drilling operations have been successfully completed with all three Villeperdue West oil wells and the Merisier side-track well online and performing ahead of forecast. In Malaysia, evaluation of a potential next phase of field development is progressing in line with schedule. IPC remains focused on organic growth and continues to mature future development projects across all operated assets, with a significant portfolio of drilling and optimisation opportunities ready for sanction at the discretion of the Group. Production Average daily net production for the third quarter 2023 was above the high end of our 2023 Capital Markets Day (CMD) guidance range at 50,200 boepd. In Canada, strong operational performance has been supplemented by the newly drilled Suffield Ellerslie production wells and earlier than forecast first oil from the production sustaining Pad L at Onion Lake Thermal. At Bertam in Malaysia, two production wells are offline with workovers scheduled for later in Q4 2023. The Bertam FPSO major planned maintenance shutdown was successfully executed in line with schedule and budget during September 2023. With exceptional operational performance during the first nine months of 2023 and the production benefit from the 2023 capital expenditure investments in Canada and France, full year 2023 average net production is expected to exceed the upper end of the CMD guidance of 48,000 to 50,000 boepd. The production during Q3 2023 with comparatives is summarized below: Production in Mboepd Three months ended September 30 Nine months ended September 30 Year ended December 31 2023 2022 2023 2022 2022 Crude oil Canada – Northern Assets 15.8 15.8 15.6 15.4 15.6 Canada – Southern Assets1 11.4 8.8 11.9 8.5 8.7 Malaysia 2.9 5.8 4.3 5.3 5.3 France 2.8 2.7 2.7 2.8 2.7 Total crude oil production 32.9 33.1 34.5 32.0 32.3 Gas Canada – Northern Assets 0.3 0.1 0.3 0.1 0.1 Canada – Southern Assets 17.0 16.8 16.8 16.3 16.2 Total gas production 17.3 16.9 17.1 16.4 16.3 Total production 50.2 50.0 51.6 48.4 48.6 Quantity in MMboe 4.62 4.60 14.09 13.21 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”. 9 ===== SIDA 33 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 CANADA Production in Mboepd WI Three months ended September 30 Nine months ended September 30 Year ended December 31 2023 2022 2023 2022 2022 - Oil Onion Lake Thermal 100% 13.4 12.9 13.2 12.5 12.7 - Oil Suffield Area1 100% 10.0 6.9 10.3 7.2 7.1 - Oil Ferguson 100% 1.4 1.9 1.6 1.3 1.6 - Oil Other 50-100% 2.4 2.9 2.4 2.9 2.9 - Gas1 ~100%2 17.3 16.9 17.1 16.4 16.3 Canada 44.5 41.5 44.6 40.3 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 Q3 2023 was above high-end CMD guidance at 44,500 boepd with continued strong operational performance at all the major producing assets. At Onion Lake Thermal, daily production has been touching the facility nameplate capacity of 14,000 boepd with the first two 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 optimisation has been supplemented by the newly drilled Suffield Ellerslie production wells which continue to exceed expectations. 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 third quarter at Blackrod, the Phase 1 development progressed in accordance with plan. Initial construction camps have been installed and site preparations are underway to allow for drilling and equipment delivery beginning in 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. As of the end of Q3 at Suffield, four out of six of the originally planned Ellerslie play wells have been brought online with initial production ahead of expectations. Given the promising production performance and robust pricing environment, IPC has elected to increase the 2023 Ellerslie drilling program to eight wells by adding two additional production wells to the Q4 2023 drilling plan. At Onion Lake Thermal, daily production is touching facility nameplate capacity of 14,000 boepd with the first two well pairs from production sustaining Pad L brought online ahead of schedule in Q3 2023. The third and fourth well pairs from the Pad are on steam warm up in preparation for first oil later in Q4 2023. MALAYSIA Production in Mboepd WI Three months ended September 30 Nine months ended September 30 Year ended December 31 2023 2022 2023 2022 2022 Bertam 100% 2.9 5.8 4.3 5.3 5.3 Production Net production at Bertam in Malaysia was below guidance at 2.9 boepd with two production wells offline and being prepared for workover later in Q4 2023. This is expected to be completed by January 2024. The Bertam FPSO planned maintenance shutdown was successfully executed in line with schedule and budget during September 2023. Organic Growth and Capital Projects In Malaysia, our focus is now on completing the two well workovers and studying 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. 10 ===== SIDA 34 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 FRANCE Production in Mboepd WI Three months ended September 30 Nine months ended September 30 Year ended December 31 2023 2022 2023 2022 2022 France - Paris Basin 100%1 2.5 2.4 2.3 2.5 2.4 - Aquitaine 50% 0.3 0.3 0.4 0.3 0.3 2.8 2.7 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 Q3 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. 11 ===== SIDA 35 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 FINANCIAL REVIEW Financial Results Selected Annual Financial Information Selected consolidated statement of operations is as follows: USD Thousands Q3-23 Q2-23 Q1-23 Q4-22 Q3-22 Q2-22 Q1-22 Q4-21 Revenue 257,366 205,564 192,516 253,921 297,952 315,540 259,782 215,296 Gross profit 93,429 52,747 64,383 95,411 140,489 161,709 119,100 79,469 Net result 71,681 32,025 39,563 61,183 90,503 105,217 80,822 66,918 Earnings per share – USD 0.56 0.24 0.29 0.45 0.63 0.70 0.52 0.43 Earnings per share fully diluted – USD 0.54 0.24 0.28 0.44 0.62 0.68 0.51 0.42 Operating cash flow1 119,142 84,372 75,900 113,668 171,654 192,515 145,110 110,687 Free cash flow1 34,703 16,415 16,259 65,288 116,681 151,792 96,479 86,960 EBITDA1 123,054 85,201 76,079 125,651 174,328 194,038 145,463 110,087 Net cash / (debt) at period end1 83,097 63,548 66,956 175,098 88,615 14,382 (42,367) (94,312) 1 See definition on page 22 under “Non-IFRS measures” Summarized consolidated balance sheet information is as follows: USD Thousands September 30, 2023 December 31, 2022 Non-current assets 1,226,851 1,041,051 Current assets 727,020 638,566 Total assets 1,953,871 1,679,617 Total non-current liabilities 748,732 564,381 Current liabilities 180,013 149,905 Total liabilities 928,745 714,286 Net assets 1,025,126 965,331 Working capital (including cash) 547,007 488,661 12 ===== SIDA 36 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 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 – September 30, 2023 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 124,468 77,045 46,148 19,318 – 266,979 NGLs – 377 – – – 377 Gas 98 16,607 – – – 16,705 Net sales of oil and gas 124,566 94,029 46,148 19,318 – 284,061 Change in under/over lift position – – – 4,349 – 4,349 Royalties (19,712) (12,261) – (1,239) – (33,212) Hedging settlement (985) 2,839 – – – 1,854 Other operating revenue – – – 229 85 314 Revenue 103,869 84,607 46,148 22,657 85 257,366 Operating costs (22,466) (40,330) (11,062) (9,004) – (82,862) Cost of blending (32,858) (6,978) – – – (39,836) Change in inventory position (151) 466 (8,478) 96 – (8,067) Depletion and decommissioning costs (9,687) (14,906) (3,438) (3,656) – (31,687) Depreciation of other tangible fixed assets – – (1,509) – – (1,509) Exploration and business development costs – – – – 24 24 Gross profit/(loss) 38,707 22,859 21,661 10,093 109 93,429 Three months ended – September 30, 2022 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 123,542 64,083 71,138 21,884 – 280,647 NGLs – 170 – – – 170 Gas 173 37,224 – – – 37,397 Net sales of oil and gas 123,715 101,477 71,138 21,884 – 318,214 Change in under/over lift position – – – 534 – 534 Royalties (13,542) (12,985) – (1,409) – (27,936) Hedging settlement 6,564 1,832 – – – 8,396 Other operating revenue – 10 – 143 – 153 Revenue 116,737 90,334 71,138 21,152 – 299,361 Operating costs (23,538) (29,867) (9,249) (8,349) – (71,003) Cost of blending (35,563) (6,795) – – – (42,358) Change in inventory position (219) (749) (8,488) 162 – (9,294) Depletion and decommissioning costs (8,488) (10,965) (9,618) (2,868) – (31,939) Depreciation of other tangible fixed assets – – (2,991) – – (2,991) Exploration and business development costs – – – – (1,287) (1,287) Gross profit/(loss) 48,929 41,958 40,792 10,097 (1,287) 140,489 13 ===== SIDA 37 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Nine months ended – September 30, 2023 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 324,963 196,420 85,924 52,476 – 659,783 NGLs – 845 – – – 845 Gas 255 52,309 – – – 52,564 Net sales of oil and gas 325,218 249,574 85,924 52,476 – 713,192 Change in under/over lift position – – – 8,842 – 8,842 Royalties (45,495) (30,218) – (3,575) – (79,288) Hedging settlement (1,620) 13,589 – – – 11,969 Other operating revenue – 7 – 639 85 731 Revenue 278,103 232,952 85,924 58,382 85 655,446 Operating costs (70,949) (116,527) (26,509) (24,609) – (238,594) Cost of blending (108,603) (19,920) – – – (128,523) Change in inventory position 190 79 2,141 (182) – 2,228 Depletion and decommissioning costs1 (15,804) (30,481) (14,818) (10,385) – (71,488) Depreciation of other tangible fixed assets – – (6,503) – – (6,503) Exploration and business development costs – (834) – (9) (1,164) (2,007) Gross profit/(loss) 82,937 65,269 40,235 23,197 (1,079) 210,559 1 In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program. Nine months ended – September 30, 2022 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 412,222 212,295 139,782 83,284 – 847,583 NGLs – 632 – – – 632 Gas 826 118,016 – – – 118,842 Net sales of oil and gas 413,048 330,943 139,782 83,284 – 967,057 Change in under/over lift position – – – (911) – (911) Royalties (49,347) (37,514) – (4,796) – (91,657) Hedging settlement 6,534 (6,994) – – – (460) Other operating revenue – 111 – 543 – 654 Revenue 370,235 286,546 139,782 78,120 – 874,683 Operating costs (78,196) (82,610) (25,657) (26,688) – (213,151) Cost of blending (115,881) (26,757) – – – (142,638) Change in inventory position 1,272 193 2,195 774 – 4,434 Depletion and decommissioning costs (24,841) (31,389) (26,020) (9,471) – (91,721) Depreciation of other tangible fixed assets – – (8,092) – – (8,092) Exploration and business development costs 97 – – – (2,314) (2,217) Gross profit/(loss) 152,686 145,983 82,208 42,735 (2,314) 421,298 14 ===== SIDA 38 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Three and nine months ended September 30, 2023, Review Revenue Total revenue amounted to USD 257,366 thousand for Q3 2023, compared to USD 299,361 thousand for Q3 2022 and USD 655,466 thousand for the first nine months of 2023 compared to USD 874,683 thousand for the first nine months of 2022 and is analyzed as follows: USD Thousands Three months ended September 30 Nine months ended September 30 2023 2022 2023 2022 Crude oil sales 266,979 280,647 659,783 847,583 Gas and NGL sales 17,082 37,567 53,409 119,474 Change in under/overlift position 4,349 534 8,842 (911) Royalties (33,212) (27,936) (79,288) (91,657) Hedging settlement 1,854 8,396 11,969 (460) Other operating revenue 314 153 731 654 Total revenue 257,366 299,361 655,446 874,683 The main components of total revenue for the three and nine months ended September 30, 2023, and September 30, 2022, respectively, are detailed below. Crude oil sales Three months ended – September 30, 2023 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 124,468 77,045 46,148 19,318 266,979 - Quantity sold in bbls 1,814,151 1,116,530 486,962 223,481 3,641,124 - Average price realized USD per bbl 68.61 69.00 94.77 86.44 73.32 Three months ended – September 30, 2022 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 123,542 64,083 71,138 21,884 280,647 - Quantity sold in bbls 1,743,766 887,736 614,329 217,875 3,463,706 - Average price realized USD per bbl 70.85 72.19 115.80 100.44 81.03 Crude oil revenue was 5% lower in Q3 2023 compared to Q3 2022 mainly due to lower oil prices. Canadian - Southern Assets sales volumes are 26% higher in Q3 2023 compared to Q3 2022 as a result of the Cor4 acquisition in Q1 2023. 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 Q3 2023, WTI averaged USD 82 per bbl compared to USD 92 per bbl for Q3 2022 and the average discount to WCS used in our pricing formula was USD 13 per bbl compared to USD 20 per bbl for Q3 2022. The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There were two cargo liftings in Malaysia during Q3 2023 and two cargo liftings in Q3 2022. Produced unsold oil barrels from Bertam at the end of Q3 2023 amounted to 146,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 87 per bbl for Q3 2023 compared to USD 101 per bbl for the comparative period. 15 ===== SIDA 39 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Nine months ended – September, 2023 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 324,963 196,420 85,924 52,476 659,783 - Quantity sold in bbls 5,525,405 3,248,704 932,654 640,586 10,347,349 - Average price realized USD per bbl 58.81 60.46 92.13 81.92 63.76 Nine months ended – September, 2022 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 412,222 212,295 139,782 83,284 847,583 - Quantity sold in bbls 5,055,871 2,591,889 1,173,230 813,116 9,634,106 - Average price realized USD per bbl 81.53 81.91 119.14 102.43 87.98 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. Crude oil revenue was lower by 22% during the first nine months of 2023 compared to the first nine months of 2022 mainly due to lower oil prices. Canadian - Southern Assets sales volumes were 25% higher in the first nine months 2023 compared to the first nine months of 2022 as a result of the Cor4 acquisition in Q1 2023. The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. For the first nine months of 2023, WTI averaged USD 77 per bbl compared to USD 98 per bbl for the comparative period and the average discount to WCS used in our pricing formula was USD 18 per bbl compared to USD 16 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 82 per bbl for the first nine months of 2023 compared to USD 106 per bbl for the comparative period. Gas and NGL sales Three months ended – September 30, 2023 Canada – Southern Assets Canada – Northern Assets Total Gas and NGL sales - Revenue in USD thousands 16,984 98 17,082 - Quantity sold in Mcf 8,541,601 55,178 8,596,779 - Average price realized USD per Mcf 1.99 1.77 1.99 Three months ended – September 30, 2022 Canada – Southern Assets Canada – Northern Assets Total Gas and NGL sales - Revenue in USD thousands 37,394 173 37,567 - Quantity sold in Mcf 8,478,728 58,742 8,537,470 - Average price realized USD per Mcf 4.41 2.95 4.40 Gas and NGL sales revenue was 55% lower for Q3 2023 compared to Q3 2022 mainly due to the lower achieved gas price. IPC’s achieved gas price is based on AECO pricing plus a premium. For Q3 2023, IPC realized an average price of CAD 2.62 per Mcf compared to AECO average pricing of CAD 2.56 per Mcf. 16 ===== SIDA 40 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Nine months ended – September 30, 2023 Canada – Southern Assets Canada – Northern Assets Total Gas and NGL sales - Revenue in USD thousands 53,154 255 53,409 - Quantity sold in Mcf 24,635,855 149,847 24,785,702 - Average price realized USD per Mcf 2.16 1.70 2.15 Nine months ended – September 30, 2022 Canada – Southern Assets Canada – Northern Assets Total Gas and NGL sales - Revenue in USD thousands 118,648 826 119,474 - Quantity sold in Mcf 24,443,007 194,580 24,637,587 - Average price realized USD per Mcf 4.85 4.24 4.85 Gas and NGL sales revenue was 55% lower for the first nine months of 2023 compared to the first nine months of 2022 mainly due to the lower achieved gas price. IPC’s achieved gas price is based on AECO pricing plus a premium. For the first nine months of 2023, IPC realized an average price of CAD 2.86 per Mcf compared to AECO average pricing of CAD 2.72 per Mcf. 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 first nine months of 2023 amounted to a gain of USD 11,969 thousand and consisted of a gain of USD 14,357 thousand on the gas contracts and a loss of USD 2,388 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 130,765 thousand for Q3 2023 compared to USD 122,655 thousand for Q3 2022 and USD 364,889 thousand for the first nine months of 2023 compared to USD 351,355 thousand for the comparative period, and is analyzed as follows: Three months ended – September 30, 2023 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Other3 Total Operating costs1 40,330 22,466 14,349 9,004 (3,287) 82,862 USD/boe2 15.46 15.19 53.25 34.64 n/a 17.95 Cost of blending 6,978 32,858 – – – 39,836 Change in inventory position (466) 151 8,478 (96) – 8,067 Production costs 46,842 55,475 22,827 8,908 (3,287) 130,765 Three months ended – September 30, 2022 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Other3 Total Operating costs1 29,867 23,538 13,389 8,349 (4,140) 71,003 USD/boe2 12.68 16.08 25.07 33.75 n/a 15.44 Cost of blending 6,795 35,563 – – – 42,358 Change in inventory position 749 219 8,488 (162) – 9,294 Production costs 37,411 59,320 21,877 8,187 (4,140) 122,655 17 ===== SIDA 41 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Nine months ended – September 30, 2023 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Other3 Total Operating costs1 116,527 70,949 37,941 24,609 (11,432) 238,594 USD/boe2 15.75 16.31 32.67 33.14 n/a 17.42 Cost of blending 19,920 108,603 – – – 128,523 Change in inventory position (79) (190) (2,141) 182 – (2,228) Production costs 136,368 179,362 35,800 24,791 (11,432) 364,889 Nine months ended – September 30, 2022 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Other3 Total Operating costs1 82,610 78,196 37,942 26,688 (12,285) 213,151 USD/boe2 12.20 18.46 26.26 35.04 n/a 16.13 Cost of blending 26,757 115,881 – – – 142,638 Change in inventory position (193) (1,272) (2,195) (774) – (4,434) Production costs 109,174 192,805 35,747 25,914 (12,285) 351,355 1 See definition on page 22 under “Non-IFRS measures”. 2 USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and 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 41.06 and USD 17.32 for Q3 2023 and Q3 2022 respectively and USD 22.83 and USD 17.76 for the nine months ended September 30, 2023 and September 30, 2022, respectively. Operating costs Operating costs amounted to USD 82,862 thousand for Q3 2023 compared to USD 71,003 thousand for Q3 2022 and USD 238,594 thousand for the first nine months of 2023 compared to USD 213,151 for the first nine months of 2022. The increase in costs in Q3 2023 compared to Q3 2022 is due mainly to increased production and activity levels. Operating costs per boe amounted to USD 17.95 per boe in Q3 2023 in line with guidance for the quarter and compared with USD 15.44 per boe in Q3 2022. Operating costs per boe for Malaysia is higher in Q3 2023 compared with Q3 2022 as a result of the lower production due to two producing wells offline and the September shutdown. The full year CMD guidance of USD 17.5 to 18 per boe remains unchanged. 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 39,836 thousand for Q3 2023 compared to USD 42,358 thousand for Q3 2022 and USD 128,523 thousand for the first nine months of 2023 compared to USD 142,638 for the comparative period. The decrease versus the comparative period is largely attributable to lower commodity pricing reflected in the cost of diluent. 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 Q3 2023, IPC had crude entitlement of 146,000 barrels of oil on the FPSO Bertam facility being crude produced but not yet sold . Two crude cargo were lifted from Bertam in July and September 2023 with the next lifting scheduled for November 2023. 18 ===== SIDA 42 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Depletion and decommissioning costs The total depletion of oil and gas properties amounted to USD 31,687 thousand for Q3 2023 compared to USD 31,939 thousand for Q3 2022 and USD 71,488 thousand for the first nine months of 2023 (including an adjustment for accelerated decommissioning activities amounting to USD 24,055 thousand) compared to USD 91,721 thousand for the first nine months of 2022. The depletion charge is analyzed in the following tables: Three months ended – September 30, 2023 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Depletion cost in USD thousands 14,906 9,687 3,438 3,656 31,687 USD per boe 5.71 6.55 12.76 14.07 6.86 Three months ended – September 30, 2022 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Depletion cost in USD thousands 10,964 8,488 9,618 2,868 31,939 USD per boe 4.66 5.80 18.01 11.59 6.94 Nine months ended – September 30, 2023 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Depletion cost in USD thousands1 42,225 28,115 14,818 10,385 95,543 USD per boe2 5.70 6.46 12.76 13.99 6.96 Nine months ended – September 30, 2022 USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Depletion cost in USD thousands 31,389 24,841 26,020 9,471 91,721 USD per boe 4.63 5.87 18.01 12.43 6.94 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 1,509 thousand for Q3 2023 compared to USD 2,991 thousand for Q3 2022 and USD 6,503 thousand for the first nine months of 2023 compared to USD 8,092 thousand for the first nine months of 2022. 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 credit of USD 24 thousand for Q3 2023 and a cost of USD 2,007 thousand for the first nine months of 2023 including Cor4 acquisition related costs amounting to USD 834 thousand. Sale of assets Sale of assets amounted to USD 11,912 thousand for Q3 2023 and represents the sale of John Lake properties in Canada in September 2023 with gross proceeds of CAD 19.4 million (USD 14.4 million) and a net accounting gain on disposal of CAD 16.0 million (USD 11.9 million). IPC completed the disposal of a further non-core property, Fishing Lake, in Canada for a consideration of CAD 3.5 million, effective August 1, 2023. As this transaction completed in October 2023, the sale will be recognized in the fourth quarter of 2023. 19 ===== SIDA 43 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Net financial items Net financial items amounted to a charge of USD 4,257 thousand for Q3 2023, compared to a charge of USD 9,225 thousand for Q3 2022 and a charge of USD 16,227 thousand for the first nine months of 2023 compared to a charge of USD 31,129 thousand for the first nine months of 2022, and included a non-cash net foreign exchange loss of USD 1,493 thousand for the first nine months of 2023 compared to a net foreign exchange loss of USD 5,945 thousand for the comparative period. The foreign exchange movements during the first nine months of 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 5,111 thousand for Q3 2023, compared to USD 7,323 thousand for Q3 2022 and a charge of USD 14,734 thousand for the first nine months of 2023 compared to a charge of 25,184 thousand for the comparative period. The interest expense amounted to USD 5,787 thousand for Q3 2023, compared to USD 5,686 thousand for the comparative period in 2022 and USD 16,591 thousand for the first nine months of 2023 compared to USD 15,201 thousand for the first nine months of 2022 and mainly related to the bond interest. Interest income generated on cash balances held in Q3 2023 amounted to USD 4,979 thousand and USD 14,238 thousand for the first nine months of 2023 and is higher than the comparative period due mainly to higher interest rates and higher cash balances. The unwinding of the asset retirement obligation discount rate amounted to USD 3,479 thousand for Q3 2023, compared to USD 2,667 thousand for Q3 2022 and USD 10,021 thousand for the first nine months of 2023 compared to USD 8,156 thousand for the first nine months of 2022. Income tax The corporate income tax amounted to a charge of USD 25,451 thousand for Q3 2023, compared to a charge of USD 37,977 thousand for Q3 2022 and a charge of USD 50,671 thousand for the first nine months of 2023 compared to a charge of USD 102,927 for the comparative period. The current income tax charge amounted to USD 7,459 thousand in Q3 2023 and USD 16,045 thousand during the first nine months of 2023 and mainly related to France and Malaysia. No corporate income tax was payable in Canada in respect of the first nine months of 2023 due to the usage of historical tax pools. Capital Expenditure Development and exploration and evaluation expenditure incurred during the first nine months of 2023 was as follows: USD Thousands Canada – Southern Assets Canada – Northern Assets Malaysia France Total Development 12,664 154,200 1,803 15,228 183,895 Exploration and evaluation – – – 9 9 12,664 154,200 1,803 15,237 183,904 Capital expenditure of USD 183,895 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project and on the Pad L completion at Onion Lake Thermal and in France on the drilling of the Villeperdue West oil wells. 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). 20 ===== SIDA 44 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 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 first nine months of 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 26,697 thousand as at September 30, 2023, which included USD 24,895 thousand in respect of the FPSO Bertam. The FPSO Bertam is being depreciated on a unit of production basis based 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 September 30, 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 further increased the Canadian RCF to 165 million. No cash amounts were drawn under the Canadian RCF as at September 30, 2023. 21 ===== SIDA 45 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 As at September 30, 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 September 30, 2023 was USD 10 million (EUR 9 million). Total net cash as at September 30, 2023 amounted to USD 83 million. IPC intends to fund the Blackrod Phase 1 development with cash on hand and forecast FCF generated by its operations. The bond repayment obligations as at September 30, 2023, are classified as non-current as there are no mandatory repayments within the next twelve months. An amount of USD 3.4 million (EUR 3.2 million) drawn under the France Facility as at September 30, 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 September 30, 2023. Cash and cash equivalents held amounted to USD 543 million as at September 30, 2023 of which USD 5.2 million was restricted. Working Capital As at September 30, 2023, the Group had a net working capital balance including cash of USD 547,007 thousand compared to USD 488,661 thousand as at December 31, 2022. The difference as at September 30, 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. 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. 22 ===== SIDA 46 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 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 September 30 Nine months ended September 30 2023 2022 2023 2022 Revenue 257,366 299,361 655,446 874,683 Production costs (130,765) (122,655) (364,889) (351,355) Current tax (7,459) (5,052) (16,045) (14,049) Operating cash flow 119,142 171,654 274,512 509,279 The operating cash flow for the first nine months of 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 279,414 thousand. 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 September 30 Nine months ended September 30 2023 2022 2023 2022 Operating cash flow - see above 119,142 171,654 274,512 509,279 Capital expenditures (76,844) (46,729) (183,904) (114,870) Abandonment and farm-in expenditures1 (2,755) (1,517) (7,683) (5,877) General, administration and depreciation expenses before depreciation2 (3,547) (2,378) (11,124) (9,499) Cash financial items3 (1,293) (4,349) (3,593) (14,079) Free cash flow 34,703 116,681 68,208 364,954 1 See note 17 to the Financial Statements 2 Depreciation is not specifically disclosed in the Financial Statements 3 See notes 4 and 5 to the Financial Statements. The free cash flow for the first nine months of 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 67,379 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 September 30 Nine months ended September 30 2023 2022 2023 2022 Net result 71,681 90,503 143,269 276,542 Net financial items 4,257 9,225 16,227 31,129 Income tax 25,451 37,977 50,671 102,927 Depletion 31,687 31,939 71,488 91,721 Depreciation of other tangible fixed assets 1,509 2,991 6,503 8,092 Exploration and business development costs (24) 1,287 2,007 2,217 Depreciation included in general, administration and depreciation expenses1 405 406 1,180 1,201 Sale of assets (11,912) – (11,912) – EBITDA 123,054 174,328 279,433 513,829 1 Item is not shown in the Financial Statements. The EBITDA for the first nine months of 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 284,334 thousand. 23 ===== SIDA 47 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Operating costs The following table sets out how operating costs is calculated: USD Thousands Three months ended September 30 Nine months ended September 30 2023 2022 2023 2022 Production costs 130,765 122,655 364,889 351,355 Cost of blending (39,836) (42,358) (128,523) (142,638) Change in inventory position (8,067) (9,294) 2,228 4,434 Operating costs 82,862 71,003 238,594 213,151 The operating costs for the first nine months of 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 245,395 thousand. Net cash The following table sets out how net cash is calculated: USD Thousands September 30, 2023 December 31, 2022 Bank loans (9,511) (12,142) Bonds1 (450,000) (300,000) Cash and cash equivalents 542,608 487,240 Net cash 83,097 175,098 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. As at September 30, 2023, following the cancellation during the first nine months of 2023 of a further 7,638,779 common shares repurchased under the NCIB, IPC had a total of 129,189,220 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 31.5% of the outstanding common shares as at September 30, 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 4,446,239 IPC Share Unit Plan awards outstanding as at October 31, 2023 (324,240 awards granted in March 2021, 1,716,000 awards granted in May 2021, 4,333 awards granted in January 2022, 1,247,998 awards granted in March 2022, 2,391 awards granted in July 2022, 2,072 awards granted in January 2023, 1,145,961 awards granted in March 2023 and 3,244 awards granted in July 2023). 24 ===== SIDA 48 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Contractual Obligations and Commitments In Canada, an oil pipeline from the Onion Lake Thermal field to a gathering system has been built by a third party for the exclusive use of IPC. The initial investment in the pipeline was met by the pipeline owner and is to be recovered through an agreed tariff charged to IPC. IPC has committed to a firm transportation service for 15 years from commencement of service in April 2022, with total remaining tariffs committed as shown in the table below: 2023 2024 2025 2026 2027 Thereafter Transportation service (MCAD) 6.9 28.0 28.4 29.0 28.2 275.2 In Malaysia, IPC has an obligation to make payments towards historic costs on Block PM307 payable on the Bertam field for every 1 MMboe gross that the field produces above 10 MMboe gross. The estimated liability based on current 2P reserves and which is capped at cumulative production of 27.5 MMboe gross, has been provided for in the Group’s Balance Sheet – see Note 17 Provisions of the Financial Statements. 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 Q3 2023, the Group paid USD 273 thousand to the Lundin Foundation in respect of sustainability advisory services provided to the Group. During Q3 2023, the Group paid USD 685 thousand to Orrön Energy (formerly Lundin Energy) in respect of office space rental for 2023. During Q3 2023, Orrön Energy paid USD 641 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 September 30, 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. 25 ===== SIDA 49 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 The Group had gas price sale financial hedges outstanding as at September 30, 2023, which are summarized as follows: Period Volume (Gigajoules (GJ) per day) Type Average Pricing October 1, 2023 – October 31, 2023 35,0001 AECO Swap CAD 3.95/GJ 1 Equivalent to 33,700 Mcf per day at CAD 4.10/Mcf. The Group had oil price sale financial hedges outstanding as at September 30, 2023 which are summarized as follows: Period Volume (barrels per day) Type Average Pricing October 1, 2023 - December 31, 2023 12,000 WCS/ARV Differential USD -10.08/bbl January 1, 2024 - December 31, 2024 17,700 WCS/WTI Differential USD -15.03/bbl January 1, 2024 - December 31, 2024 2,500 WTI Sale Swap USD 81.16/bbl The Group had condensate financial hedges outstanding as at September 30, 2023 which are summarized as follows: Period Volume (barrels per day) Type Average Pricing October 31, 2023 – March 31, 2024 3,000 C5/WTI Differential USD -1.60/bbl The Group had electricity financial hedges outstanding as at September 30, 2023 which are summarized as follows: Period Volume (MW) Type Pricing October 1, 2025 - September 1, 2040 3 AESO CAD 75.00/MWh In October 2022, IPC entered into currency hedge swaps for 2023 to buy CAD 15 million per month, sell USD at an average exchange rate of 1.36 and to buy EUR 3 million per month, sell USD at an average exchange rate of 1.00. In June 2023, IPC entered into currency hedge swaps for 2023 to buy MYR 13 million per month, sell USD at an average exchange rate of 4.54. This is to partially fund forecast operational expenditures in those currencies in Canada, France and Malaysia respectively. In respect of the forecast Blackrod development capital expenditure in Canada, IPC had foreign currency hedge swaps outstanding at September 30, 2023 summarized as follows: Period Total Amount to Buy Type Average CAD/USD Rate October 2023 - March 2025 Buy MCAD 436 Forward Swap 1.31 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 13,858 thousand as at September 30, 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 October 2022, IPC entered into currency hedge swaps for 2023 to buy CAD 15 million per month, sell USD at an average exchange rate of 1.36 and to buy EUR 3 million per month, sell USD at an average exchange rate of 1.00. In June 2023, IPC entered into currency hedge swaps for the second six months of 2023 to buy MYR 13 million per month, sell USD at an average exchange rate of 4.54. This is to partially fund operational expenditures in those currencies in Canada, France and Malaysia respectively. The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The currency hedge swaps had a negative fair value of USD 8,857 thousand as at September 30, 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. 26 ===== SIDA 50 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 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 AND UNCERTAINTIES IPC is engaged in the exploration, development and production of oil and gas and is exposed to various operational, environmental, market and financial risks and uncertainties. For further information and discussion of these risks and uncertainties, please see IPC’s Annual Information Form for the year ended December 31, 2022 (”AIF”) available on SEDAR+ at www.sedarplus.ca or on IPC’s website at www.international-petroleum.com. See also “Cautionary Statement Regarding Forward Looking Information” and “Reserves and Resource Advisory” in this MD&A. 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 nine month period ended September 30, 2023, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial reporting. 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: • 2023 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; • IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the Corporation; • The ability to fully fund future expenditures from cash flows and current borrowing capacity; 27 ===== SIDA 51 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 • 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 intention and ability to continue to implement our 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; • Future development potential of the Suffield and Ferguson operations in Canada, including the timing and success of future oil and gas drilling and optimisation programs; • 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; • Current and future drilling pad production 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 ability of IPC to acquire further common shares under the NCIB, including the timing of any such purchases; • The ability of IPC to renew the NCIB and the number of common shares which may be purchased under a renewed NCIB; • 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 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 Resource 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; 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” 28 ===== SIDA 52 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 Estimated FCF generation is based on IPC’s current business plans over the periods of 2023 to 2027 and 2028 to 2032. Assumptions include average net production of approximately 50 Mboepd over the period of 2023 to 2027, average net production of approximately 65 Mboepd over the period of 2028 to 2032, 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 AIF . 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 Annual Information Form (AIF) for the year ended December 31, 2022, (See “Cautionary Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk and Uncertainties”) 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 (other than the assets acquired in the Cor4 acquisition) are effective as of December 31, 2022, 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, 2022 price forecasts. Reserve estimates and estimates of future net revenue in respect of IPC’s oil and gas assets acquired in the Cor4 acquisition are effective as of December 31, 2022, and have been audited by GLJ Ltd. (GLJ), an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 31, 2022, 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, 2022, 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, 2022 price forecasts. The price forecasts used in the Sproule, GLJ and ERCE reports, are available on the website of Sproule (sproule. com) and are contained in the AIF . These price forecasts are as at December 31, 2022 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 487 MMboe as at December 31, 2022 (including 15.9 MMboe acquired in the Cor4 acquisition), by the mid-point of the 2023 CMD production guidance of 48,000 to 50,000 boepd. The product types comprising the 2P reserves described in this MD&A are contained in the AIF . 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. 29 ===== SIDA 53 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 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 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 associated with the resolution of all contingencies required for the re-classification of the contingent resources as reserves. Therefore 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 the 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 the MD&A. 2P reserves and contingent resources included in the reports prepared by Sproule, GLJ 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. 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. 30 ===== SIDA 54 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 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 September 30, 2023 25.8 7.1 103.4 MMcf (17.3 Mboe) 50.2 September 30, 2022 22.7 10.4 101.5 MMcf (16.9 Mboe) 50.0 Nine months ended September 30, 2023 25.9 8.6 102.4 MMcf (17.1 Mboe) 51.6 September 30, 2022 22.6 9.4 98.1 MMcf (16.4 Mboe) 48.4 Year ended December 31, 2022 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 48,000 to 50,000 boepd for 2023. IPC estimates that approximately 51% of that production will be comprised of heavy oil, approximately 16% will be comprised of light and medium crude oil and approximately 33% will be comprised of conventional natural gas. 31 ===== SIDA 55 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 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 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. 32 ===== SIDA 56 ===== Management’s Discussion and Analysis For the three and nine months ended September 30, 2023 DIRECTORS C. Ashley Heppenstall Director, Chair London, England Mike Nicholson Director, President and Chief Executive Officer Geneva, Switzerland Chris Bruijnzeels Director Abcoude, The Netherlands Donald K. Charter Director Toronto, Ontario, Canada Emily Moore Director Toronto, Ontario, Canada Lukas (Harry) H. Lundin Director Toronto, Ontario, Canada OFFICERS Christophe Nerguararian Chief Financial Officer Geneva, Switzerland William Lundin Chief Operating Officer Geneva, Switzerland Jeffrey Fountain General Counsel and Corporate Secretary Geneva, Switzerland Rebecca Gordon VP 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 MEDIA AND INVESTOR RELATIONS Robert Eriksson Stockholm, Sweden Sophia Shane Vancouver, British Columbia, Canada 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 33 ===== SIDA 57 ===== 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□