Interim report
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3 International Petroleum Corporation Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026
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2 Contents Interim Condensed Consolidated Statement of Operations 3 Interim Condensed Consolidated Statement of Comprehensive Income/(Loss) 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, 2026 and 2025, UNAUDITED
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3 Interim Condensed Consolidated Statement of Operations For the three and nine months ended September 30, 2026 and 2025, UNAUDITED Three months ended September 30 Nine months ended September 30 USD Thousands Note 2026 2025 2026 2025 Revenue 2 211,955 172,297 570,703 509,681 Cost of sales Production costs 3 (128,760) (106,383) (351,932) (313,672) Depletion and decommissioning costs 7 (30,428) (32,245) (89,161) (90,582) Depreciation of other tangible fixed assets 7 – (1,419) – (4,797) Exploration and business development costs (434) (184) (2,008) (752) Gross profit 2 52,333 32,066 127,602 99,878 Sale of assets 7 45,230 – 51,451 104 Other income/(expenses) 208 91 553 510 General and administrative expenses (4,443) (4,295) (12,946) (13,007) Profit before financial items 93,328 27,862 166,660 87,485 Net financial items (12,541) (21,030) (55,663) (39,726) Profit before tax 80,787 6,832 110,997 47,759 Income tax expense 5 (20,886) (3,030) (28,417) (13,876) Net result 59,901 3,802 82,580 33,883 Net result attributable to: Shareholders of the Parent Company 59,896 3,801 82,569 33,878 Non-controlling interest 5 1 11 5 59,901 3,802 82,580 33,883 Earnings per share – USD 1 13 0.53 0.03 0.73 0.29 Earnings per share fully diluted – USD1 13 0.52 0.03 0.72 0.28 1 Based on net result attributable to shareholders of the Parent Company See accompanying notes to the interim condensed consolidated financial statements
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4 Interim Condensed Consolidated Statement of Comprehensive Income/(Loss) For the three and nine months ended September 30, 2026 and 2025, UNAUDITED Three months ended September 30 Nine months ended September 30 USD Thousands Note 2026 2025 2026 2025 Net result 59,901 3,802 82,580 33,883 Other comprehensive income/(loss) Items that may be reclassified to profit or loss: Reclassification of hedging (gains)/losses to profit or loss 2,4,5 (2,884) (6,066) 36,973 (2,707) (Loss)/Gain on cash flow hedges 2,174 (5,655) (34,216) 31,994 Income tax relating to these items (227) 2,914 (1,014) (6,856) Currency translation adjustments 3,444 (17,062) (35,170) 35,979 Total comprehensive income/(loss) 62,408 (22,067) 49,153 92,293 Total comprehensive income attributable to: Shareholders of the Parent Company 62,403 (22,068) 49,144 92,283 Non-controlling interest 5 1 9 10 62,408 (22,067) 49,153 92,293 See accompanying notes to the interim condensed consolidated financial statements
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5 Interim Condensed Consolidated Balance Sheet As at September 30, 2026 and December 31, 2025, UNAUDITED USD Thousands Note September 30, 2026 December 31, 2025 ASSETS Non-current assets Exploration and evaluation assets 6 13,091 11,623 Property, Plant and Equipment 7 1,780,258 1,783,498 Right-of-use assets 2,683 3,070 Deferred tax assets 5 1,625 1,635 Derivative instruments 17 2,060 1,285 Other non-current assets 8 47,386 46,216 Total non-current assets 1,847,103 1,847,327 Current assets Inventories 9 44,597 19,990 Trade and other receivables 10 136,153 97,220 Derivative instruments 17 6,510 1,644 Current tax receivables 1,390 4,411 Cash and cash equivalents 11 22,315 7,037 Total current assets 210,965 130,302 TOTAL ASSETS 2,058,068 1,977,629 LIABILITIES Non-current liabilities Financial liabilities 17 45,124 38,709 Bonds 17 443,536 442,324 Lease liabilities 2,521 2,956 Provisions 15 283,180 284,202 Deferred tax liabilities 5 142,659 122,013 Total non-current liabilities 917,020 890,204 Current liabilities Trade and other payables 16 183,022 149,708 Financial liabilities 17 – 1,943 Derivative instruments 17 1,807 422 Current tax liabilities 4,488 216 Lease liabilities 973 930 Provisions 15 4,123 7,029 Total current liabilities 194,413 160,248 EQUITY Shareholders’ equity 946,478 927,029 Non-controlling interest 157 148 Net shareholders’ equity 946,635 927,177 TOTAL EQUITY AND LIABILITIES 2,058,068 1,977,629 Approved by the Board of Directors (Signed) C. Ashley Heppenstall (Signed) William Lundin Director Director See accompanying notes to the interim condensed consolidated financial statements
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6 Interim Condensed Consolidated Statement of Cash Flow For the three and nine months ended September 30, 2026 and 2025, UNAUDITED Three months ended September 30 Nine months ended September 30 USD Thousands Note 2026 2025 2026 2025 Cash flow from operating activities Net result 59,901 3,802 82,580 33,883 Adjustments for non-cash related items: Depletion, depreciation and amortization 2,7 30,850 34,060 90,310 96,438 Gain on sale of assets 7 (45,230) – (51,451) – Income tax 5 20,886 3,030 28,417 13,876 Amortization of capitalized financing fees 4 576 538 1,700 1,586 Foreign currency exchange loss/(gain) 4 (2,173) 5,731 11,579 (8,502) Interest income 4 (280) (501) (626) (2,829) Interest expense 4 9,924 10,082 29,535 27,823 Unwinding of asset retirement obligation discount 4 4,079 4,229 12,364 12,301 Share-based costs 2,918 2,455 8,530 7,164 Changes in working capital (24,800) (641) (49,564) 17,689 Decommissioning costs paid 15 (1,317) (1,739) (2,365) (4,157) Other payments 15 (559) (646) (1,339) (1,474) Net income taxes refunded/(paid) (47) (1,441) 1,595 (3,529) Interest received 206 810 538 3,444 Interest paid (1,365) (16,867) (21,070) (33,273) Other 693 639 1,282 2,690 Net cash flow from operating activities 54,262 43,541 142,015 163,130 Cash flow used in investing activities Investment in oil and gas properties 7 (35,969) (80,128) (152,770) (276,939) Investment in exploration and evaluation assets 6 (57) – (1,915) – Disposal of assets 46,973 – 53,194 – Investment in other tangible fixed assets 7 (474) (189) (605) (410) Net cash (outflow) from investing activities 10,473 (80,317) (102,096) (277,349) Cash flow from financing activities Proceeds from borrowings 14 181,635 26,576 489,800 26,576 Repayment of borrowings 14 (207,801) (780) (483,801) (1,949) Repurchase of own shares (“NCIB”), including taxes 12 (26,967) (21,560) (28,923) (100,264) Paid financing fees – – – (686) Lease payments (283) (206) (927) (670) Dividend – – – (16) Net cash (outflow) from financing activities (53,416) 4,030 (23,851) (77,009) Change in cash and cash equivalents 11,319 (32,746) 16,068 (191,228) Cash and cash equivalents at the beginning of the period 11,248 78,886 7,037 246,593 Currency exchange difference in cash and cash equivalents (252) (1,479) (790) (10,704) Cash and cash equivalents at the end of the period 22,315 44,661 22,315 44,661 See accompanying notes to the interim condensed consolidated financial statements
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7 Interim Condensed Consolidated Statement of Changes in Equity For the nine month periods ended September 30, 2026 and 2025, 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, 2026 40,909 896,692 (30,594) 19,515 1,913 (1,406) 927,029 148 927,177 Net result – 82,569 – – – – 82,569 11 82,580 Cash flow hedges – – – – 1,743 – 1,743 – 1,743 Currency translation difference – – (36,131) (536) 1,499 – (35,168) (2) (35,170) Total comprehensive income – 82,569 (36,131) (536) 3,242 – 49,144 9 49,153 Repurchase of own shares (NCIB)1 (27,506) – – – – – (27,506) – (27,506) Share based costs – – – 8,530 – – 8,530 – 8,530 Share based payments2 13,555 (13,538) – (10,736) – – (10,719) – (10,719) Balance at September 30, 2026 26,958 965,723 (66,725) 16,773 5,155 (1,406) 946,478 157 946,635 1 See Note 12 2 The third instalment of IPC RSP 2023 awards, the second instalment of IPC RSP 2024 awards, the first instalment of IPC RSP 2025 awards and the IPC PSP 2023 awards vested on February 1, 2026, at a price of CAD 27.18 per award. The difference between the value at vesting date and at grant (respectively CAD 14.24 per award, CAD 14.82 per award, CAD 14.90 per award and CAD 11.51 per award) was offset against retained earnings. The impact from the issuance of common shares in settlement under IPC’s Share Unit Plan was recorded within share capital and 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, 2025 141,173 875,952 (81,192) 18,092 (13,138) (1,572) 939,315 155 939,470 Net result – 33,878 – – – – 33,878 5 33,883 Cash flow hedges – – – – 22,431 – 22,431 – 22,431 Currency translation difference – – 35,755 548 (329) – 35,974 5 35,979 Total comprehensive income – 33,878 35,755 548 22,102 – 92,283 10 92,293 Repurchase of own shares (NCIB) 1 (100,264) – – – – – (100,264) – (100,264) Dividend Distribution – – – – – – – (16) (16) Share based costs – – – 7,164 – – 7,164 – 7,164 Share based payments2 – (8,198) – (9,006) – – (17,204) – (17,204) Balance at September 30, 2025 40,909 901,632 (45,437) 16,798 8,964 (1,572) 921,294 149 921,443 1 See Note 12 2 The third instalment of IPC RSP 2022 awards, the second instalment of IPC RSP 2023 awards, the first instalment of IPC RSP 2024 awards and the IPC PSP 2022 awards vested on February 1, 2025, at a price of CAD 18.89 per award. The difference between the value at vesting date and at grant (respectively CAD 9.09 per award, CAD 14.24 per award, CAD 14.82 per award and CAD 8.40 per award) was offset against retained earnings. See accompanying notes to the interim condensed consolidated financial statements
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8 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED 1. CORPORATE INFORMATION AND MATERIAL ACCOUNTING POLICIES A. The Group International Petroleum Corporation (“IPC” or the “Corporation” and, together with its subsidiaries, the “Group”) is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development projects in Canada, Malaysia and France with exposure to growth opportunities. The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada under the Business Corporations Act. The address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada. B. Basis of preparation The unaudited interim condensed consolidated financial statements have been prepared in accordance with IFRS Accounting Standards applicable to the preparation of interim financial statements, under International Accounting Standard 34, Interim Financial Reporting (together “IFRS Accounting Standards“). The unaudited interim condensed consolidated financial statements should be read in conjunction with IPC’s annual audited consolidated financial statements for the year ended December 31, 2025, which have been prepared in accordance with IFRS Accounting Standards as issued by the IASB. These unaudited interim condensed consolidated financial statements are presented in United States Dollars (USD), which is the Group’s presentation and functional currency. The unaudited interim condensed 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. The unaudited interim condensed consolidated financial statements have been approved by the Board of Directors of IPC and authorized for issuance on November 3, 2026. 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, 2025. C. Change in presentation During the current period, IPC revised the presentation on the face of the Interim Condensed Consolidated Statement of Operations by presenting finance income and finance expenses on a consolidated basis within ‘Net financial items’. In addition, certain comparative figures have been reclassified to conform with the financial statements presentation in the current year. D. Going concern The Group’s unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2026 have been prepared on a going concern basis, which assumes that the Group will be able to realize its assets and discharge its liabilities in the normal course of business as they become due in the foreseeable future. E. Changes in accounting policies and disclosures Recent amendments to IFRS 9 and related IFRS 7 disclosure requirements address the settlement of financial liabilities via electronic payment systems and refine the assessment of contractual cash flow characteristics for financial assets. The amendments are effective for annual reporting periods beginning on or after January 1, 2026. These changes have not a material impact on the financial statements. IFRS 18 replaces IAS 1 and introduces expanded requirements for how financial information is presented and disclosed. The standard adds new subtotals, categories for income and expenses, and mandates disclosure of management performance measures. It also enhances rules around aggregation and disaggregation. Adoption is retrospective, and the Corporation is currently assessing system changes, preparing draft disclosures, and planning comparative restatements ahead of the 2027 effective date. The material accounting policies applied are consistent with those applied in the 2025 annual financial statements, except as described below. Property, plant and equipment - Determination of availability for intended use An asset under construction is considered available for its intended use when it is in the location and condition necessary for it to be capable of operating in the manner intended by management. This assessment is based on the asset’s technical and physical readiness and does not require the asset to have reached full production capacity or targeted profitability. In determining when an asset is available for its intended use, the Group applies judgement and considers the relevant facts and circumstances, including completion of the construction and commissioning activities necessary for operation, satisfactory testing of the asset’s technical and physical performance, availability of the infrastructure required for operation, and receipt of the approvals necessary to operate. At that date, capitalisation of costs to prepare the asset for use ceases and depreciation starts.
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9 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED 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, other operating costs and gross profit/ (loss). The Group derives its revenue from contracts with customers primarily through the transfer of oil and gas at a point in time. In addition, certain identifiable asset segment information is reported in Note 6 and 7. Three months ended September 30, 2026 USD Thousands Canada Malaysia France Other Total Crude oil 188,400 23,051 19,560 – 231,011 Gas and NGLs 7,992 – – – 7,992 Net sales of oil and gas 196,392 23,051 19,560 – 239,003 Change in under/over lift position – – 37 – 37 Royalties (29,115) – (1,173) – (30,288) Hedging settlement 2,884 – – – 2,884 Other operating revenue – – 170 149 319 Revenue 170,161 23,051 18,594 149 211,955 Operating costs (62,181) (12,875) (9,529) – (84,585) Cost of blending (43,936) – – – (43,936) Change in inventory position (1,279) 545 495 – (239) Depletion and decommissioning costs (22,516) (4,440) (3,472) – (30,428) Exploration and business development costs – – – (434) (434) Gross profit/(loss) 40,249 6,281 6,088 (285) 52,333 Three months ended September 30, 2025 USD Thousands Canada Malaysia France Other Total Crude oil 154,454 15,581 11,870 – 181,905 Gas and NGLs 4,807 – – – 4,807 Net sales of oil and gas 159,261 15,581 11,870 – 186,712 Change in under/over lift position – – 1,585 – 1,585 Royalties (21,941) – (931) – (22,872) Hedging settlement 6,587 – – – 6,587 Other operating revenue – – 197 88 285 Revenue 143,907 15,581 12,721 88 172,297 Operating costs (56,465) (10,908) (8,254) – (75,627) Cost of blending (32,451) – – – (32,451) Change in inventory position (379) 2,327 (253) – 1,695 Depletion and decommissioning costs (22,785) (6,504) (2,956) – (32,245) Depreciation of other tangible fixed assets – (1,419) – – (1,419) Exploration and business development costs – – – (184) (184) Gross profit/(loss) 31,827 (923) 1,258 (96) 32,066
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10 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED Nine months ended September 30, 2026 USD Thousands Canada Malaysia France Other Total Crude oil 536,018 70,132 57,232 – 663,382 Gas and NGLs 29,461 – – – 29,461 Net sales of oil and gas 565,479 70,132 57,232 – 692,843 Change in under/over lift position – – (4,707) – (4,707) Royalties (78,418) – (2,906) – (81,324) Hedging settlement (36,973) – – – (36,973) Other operating revenue – – 536 328 864 Revenue 450,088 70,132 50,155 328 570,703 Operating costs (161,128) (37,316) (27,818) – (226,262) Cost of blending (130,391) – – – (130,391) Change in inventory position (402) 4,569 554 – 4,721 Depletion and decommissioning costs (63,794) (16,007) (9,360) – (89,161) Exploration and business development costs – – – (2,008) (2,008) Gross profit/(loss) 94,373 21,378 13,531 (1,680) 127,602 Nine months ended September 30, 2025 USD Thousands Canada Malaysia France Other Total Crude oil 456,478 42,785 36,147 – 535,410 Gas and NGLs 26,539 – – – 26,539 Net sales of oil and gas 483,017 42,785 36,147 – 561,949 Change in under/over lift position – – 4,285 – 4,285 Royalties (65,614) – (2,503) – (68,117) Hedging settlement 10,746 – – – 10,746 Other operating revenue – – 572 246 818 Revenue 428,149 42,785 38,501 246 509,681 Operating costs (159,256) (31,257) (24,789) – (215,302) Cost of blending (103,446) – – – (103,446) Change in inventory position (366) 5,869 (427) – 5,076 Depletion and decommissioning costs (65,421) (17,146) (8,015) – (90,582) Depreciation of other tangible fixed assets – (4,797) – – (4,797) Exploration and business development costs – – – (752) (752) Gross profit/(loss) 99,660 (4,546) 5,270 (506) 99,878
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11 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED 3. PRODUCTION COSTS Three months ended September 30 Nine months ended September 30 USD Thousands 2026 2025 2026 2025 Cost of operations 72,391 64,024 192,283 183,141 Tariff and transportation expenses 10,843 10,498 30,338 28,947 Direct production taxes 1,351 1,105 3,641 3,214 Operating costs 84,585 75,627 226,262 215,302 Cost of blending1 43,936 32,451 130,391 103,446 Change in inventory position 239 (1,695) (4,721) (5,076) Total production costs 128,760 106,383 351,932 313,672 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. NET FINANCIAL ITEMS Three months ended September 30 Nine months ended September 30 USD Thousands 2026 2025 2026 2025 Interest income 280 501 626 2,829 Interest expense (9,924) (10,082) (29,535) (27,823) Unwinding of asset retirement obligation discount (4,079) (4,229) (12,364) (12,301) Amortization of capitalized financing fees (576) (538) (1,700) (1,586) Loan commitment fees (263) (175) (643) (719) Foreign exchange gain/(loss), net 2,173 (5,731) (11,579) 8,502 Currency hedge gain/(loss), net – (521) – (8,039) Other financial costs (152) (255) (468) (589) Total Net Financial items (12,541) (21,030) (55,663) (39,726) 5. INCOME TAX Three months ended September 30 Nine months ended September 30 USD Thousands 2026 2025 2026 2025 Current tax (4,019) 97 (5,687) (754) Deferred tax (16,867) (3,127) (22,730) (13,122) Total tax expense (20,886) (3,030) (28,417) (13,876)
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12 Specification of deferred tax assets and tax liabilities1 USD Thousands September 30, 2026 December 31, 2025 Unused tax loss carry forward 80,440 65,825 Other 7,594 6,858 Deferred tax assets 88,034 72,683 Accelerated allowances 227,459 192,464 Derivative hedges 1,609 597 Deferred tax liabilities 229,068 193,061 Deferred taxes, net (141,034) (120,378) 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 budgets and reserves reports. 6. EXPLORATION AND EVALUATION ASSETS USD Thousands Canada Malaysia France Total Cost January 1, 2026 11,623 – – 11,623 Additions 1,915 – – 1,915 Currency translation adjustments (447) – – (447) Net book value September 30, 2026 13,091 – – 13,091 USD Thousands Canada Malaysia France Total Cost January 1, 2025 480 – – 480 Acquisitions 7,311 – – 7,311 Additions 5,036 – 15 5,051 Write-off – – (15) (15) Reclassification (1,305) – – (1,305) Currency translation adjustments 101 – – 101 Net book value December 31, 2025 11,623 – – 11,623 Impairment test As of September 30, 2026, the Group determined that no internal or external indicators of impairment existed on its exploration and evaluation assets; therefore, the performance of an impairment test was determined not to be necessary (similar as of De- cember 31, 2025). Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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13 7. PROPERTY, PLANT AND EQUIPMENT USD Thousands 2026 2025 Oil and gas properties 1,768,866 1,772,278 Other tangible fixed assets 11,392 11,220 Property, Plant and Equipment 1,780,258 1,783,498 Oil and gas properties USD Thousands Canada Malaysia France Total Cost January 1, 2026 2,141,610 640,581 465,622 3,247,813 Additions 128,821 1,993 21,956 152,770 Disposals1 (10,553) – – (10,553) Change in estimates (2,493) – – (2,493) Currency translation adjustments (77,051) – (16,010) (93,061) September 30, 2026 2,180,334 642,574 471,568 3,294,476 Accumulated depletion January 1, 2026 (563,215) (554,509) (357,811) (1,475,535) Depletion charge for the period (63,794) (16,007) (9,360) (89,161) Disposals1 6,122 – – 6,122 Currency translation adjustments 20,861 – 12,103 32,964 September 30, 2026 (600,026) (570,516) (355,068) (1,525,610) Net book value September 30, 2026 1,580,308 72,058 116,500 1,768,866 1 This amount relates to the disposal of the Mooney heavy oil asset in Canada and other minor asset disposals in Canada. The Mooney asset was sold in Q3 2026 for CAD 65 million (USD 47 million) after closing adjustments and had a net carrying value of CAD 3 million (USD 2 million), resulting in a gain on disposal of CAD 62 million (USD 45 million). During the second quarter of 2026, the Blackrod Phase 1 project was deemed ready for use in the manner intended by management therefore operating results are now reported within the income statement. Initial operating results from the Blackrod Phase 1 project were capitalized until June 1, 2026. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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14 USD Thousands Canada Malaysia France Total Cost January 1, 2025 1,767,580 599,734 405,129 2,772,443 Additions 286,570 40,877 5,759 333,206 Change in estimates (9,845) (30) 1,959 (7,916) Reclassification 1,305 – – 1,305 Currency translation adjustments 96,000 – 52,775 148,775 December 31, 2025 2,141,610 640,581 465,622 3,247,813 Accumulated depletion January 1, 2025 (451,017) (530,315) (306,624) (1,287,956) Depletion charge for the year (87,449) (24,194) (11,106) (122,749) Currency translation adjustments (24,749) – (40,081) (64,830) December 31, 2025 (563,215) (554,509) (357,811) (1,475,535) Net book value December 31, 2025 1,578,395 86,072 107,811 1,772,278 Impairment test As of September 30, 2026, the Group determined that no internal or external indicators of impairment existed on its oil and gas properties; therefore, the performance of an impairment test was determined not to be necessary (similar as of December 31, 2025). Other tangible fixed assets USD Thousands FPSO Other1 Total Cost January 1, 2026 204,853 11,247 216,100 Additions – 605 605 Disposals – (32) (32) Currency translation adjustments – (338) (338) September 30, 2026 204,853 11,482 216,335 Accumulated depreciation January 1, 2026 (195,653) (9,227) (204,880) Depreciation charge for the period – (361) (361) Disposals – 32 32 Currency translation adjustments – 266 266 September 30, 2026 (195,653) (9,290) (204,943) Net book value September 30, 2026 9,200 2,192 11,392 1 Depreciation of Other is included in general and administrative expenses in the statement of operations. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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15 USD Thousands FPSO Other1 Total Cost January 1, 2025 204,853 9,824 214,677 Additions – 640 640 Disposals – (29) (29) Currency translation adjustments – 812 812 December 31, 2025 204,853 11,247 216,100 Accumulated depreciation January 1, 2025 (190,056) (8,196) (198,252) Depreciation charge for the year (5,597) (397) (5,994) Disposals – 29 29 Currency translation adjustments – (663) (663) December 31, 2025 (195,653) (9,227) (204,880) Net book value December 31, 2025 9,200 2,020 11,220 1 Depreciation of Other is included in general and administrative expenses in the statement of operations. The Floating Production Storage and Offloading facility (“FPSO“) located on the Bertam field, Malaysia, was depreciated to its residual value to August 2025. The depreciation charge was included in the depreciation of other assets line in the Statement of Operations in 2025. For office equipment and other assets, the depreciation charge for the year is based on cost and an estimated useful life of 3 to 5 years. The depreciation charge is included within the general and administrative expenses in the Statement of Operations. 8. OTHER NON-CURRENT ASSETS USD Thousands September 30, 2026 December 31, 2025 Financial assets 34,376 34,545 Intangible assets 13,010 11,671 47,386 46,216 Financial assets mainly represent cash payments made in local currency to an asset retirement obligation fund for the Bertam field, Malaysia for an amount equivalent of USD 34.4 million (2025: USD 34.5 million), see note 15. Intangible assets mainly represent carbon offsets purchased in Canada. 9. INVENTORIES USD Thousands September 30, 2026 December 31, 2025 Hydrocarbon stocks 36,594 11,995 Well supplies and operational spares 8,003 7,995 44,597 19,990 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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16 10. TRADE AND OTHER RECEIVABLES USD Thousands September 30, 2026 December 31, 2025 Trade receivables 111,971 73,245 Underlift – 6,704 Joint operations debtors 1,464 2,292 Prepaid expenses and accrued income 16,358 8,437 Other1 6,360 6,542 136,153 97,220 1 Other includes a cash collateralized guarantee placed in respect of work commitments in Malaysia amounting to USD 4.0 million. The related work commitments were completed and subsequently, the guarantee was cancelled and the cash collateral was released in October 2026. 11. CASH AND CASH EQUIVALENTS Cash and cash equivalents include only cash at hand or held in bank accounts. 12. SHARE CAPITAL The Corporation’s issued common share capital is as follows: Number of shares Balance at January 1, 2025 119,169,471 Cancellation of repurchased common shares (7,013,944) Balance at December 31, 2025 112,155,527 Issuance of common shares 671,225 Cancellation of repurchased common shares (1,099,086) Balance at September 30, 2026 111,727,666 The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. The Corporation is authorized to issue an unlimited number of Common Shares without par value. As at January 1, 2025, IPC had a total of 119,169,471 common shares issued and outstanding, of which 110,156 common shares were held in treasury. Over the period of January 1, 2025 to December 4, 2025, IPC purchased and cancelled 6,641,970 common shares under the normal course issuer bid (NCIB) and 261,818 common shares under certain other exemptions in Canada. In the first quarter of 2026, IPC paid USD 2 million of taxes in Canada in connection to the common shares repurchased in 2025 (or 2% of the total repurchase consideration). As at December 31, 2025, IPC had a total of 112,155,527 common shares issued and outstanding, with no common shares held in treasury. In February 2026, IPC issued 671,225 common shares in connection with the vesting of previously issued IPC Share Unit Plan awards. During the first nine months of 2026, IPC purchased and cancelled a total of 1,099,086 common shares under the NCIB. The average price of common shares purchased during the first nine months of 2026 was SEK 234 / CAD 34. As at September 30, 2026, IPC had a total of 111,727,666 common shares issued and outstanding, with no common shares held in treasury. In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on matters to be decided by the holders of IPC’s common shares. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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17 13. 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 2026 2025 2026 2025 Net result attributable to shareholders of the Parent Company, USD 59,895,852 3,801,000 82,568,394 33,878,000 Weighted average number of shares for the period 112,814,805 113,341,626 112,605,550 117,250,357 Earnings per share, USD 0.53 0.03 0.73 0.29 Weighted average diluted number of shares for the period 114,387,456 115,071,207 114,178,201 118,979,939 Earnings per share fully diluted, USD 0.52 0.03 0.72 0.28 14. FINANCIAL LIABILITIES USD Thousands September 30, 2026 December 31, 2025 Current bank loans – 1,943 Non current bank loans 45,124 38,709 Bonds 450,000 450,000 Capitalized financing fees (6,464) (7,676) 488,660 482,976 As at January 1, 2025, IPC had USD 450 million of senior unsecured bonds outstanding, maturing in February 2027 with a fixed coupon rate of 7.25% per annum. In October 2025, IPC completed the issuance of USD 450 million of new senior unsecured bonds, maturing in October 2030 with a fixed coupon rate of 7.50% per annum, payable in semi-annual instalments in April and October, and with semi-annual amortizations of USD 25 million commencing in April 2028. The proceeds of the new bonds were used to fully redeem and cancel the previous bonds. The bond repayment obligations as at September 30, 2026, are classified as non-current as there are no mandatory repayments within the next twelve months. In addition, as at September 30, 2026, the Group had a senior secured revolving credit facility of CAD 348.5 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada, with a maturity date in May 2028. As at September 30, 2026, CAD 64 million (approximately USD 45 million) was drawn under the Canadian RCF . As at September 30, 2026, the Group also had a letter of credit facility in Canada (the “LC Facility”). As at September 30, 2026, operational letters of credit in an aggregate of CAD 11.9 million have been issued under the LC Facility. The Group is in compliance with the covenants of the bonds and its financing facilities as at September 30, 2026. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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18 15. PROVISIONS USD Thousands Asset retirement obligation Farm-in obligation Pension obligation Other Total January 1, 2026 284,532 1,230 3,372 2,097 291,231 Additions – – – 575 575 Disposals (3,305) – – – (3,305) Unwinding of asset retirement obligation discount 12,364 – – – 12,364 Payments (2,365) (613) – (726) (3,704) Change in estimates (2,493) – – – (2,493) Currency translation adjustments (7,328) (5) – (32) (7,365) September 30, 2026 281,405 612 3,372 1,914 287,303 Non-current 277,894 – 3,372 1,914 283,180 Current 3,511 612 – – 4,123 Total 281,405 612 3,372 1,914 287,303 USD Thousands Asset retirement obligation Farm-in obligation Pension obligation Other Total January 1, 2025 267,790 1,679 3,685 2,072 275,226 Additions – – 816 815 1,631 Unwinding of asset retirement obligation discount 16,498 – – – 16,498 Payments (5,967) (587) (963) (897) (8,414) Change in estimates (7,916) – (654) – (8,570) Reclassification1 725 – – – 725 Currency translation adjustments 13,402 138 488 107 14,135 December 31, 2025 284,532 1,230 3,372 2,097 291,231 Non-current 278,733 – 3,372 2,097 284,202 Current 5,799 1,230 – – 7,029 Total 284,532 1,230 3,372 2,097 291,231 1 The reclassification of the asset retirement obligation related to the 2025 payment to the asset retirement obligation fund in respect of the Bertam asset, Malaysia (see Note 8). The farm-in obligation relates to future payments for historic costs on the Bertam field in Malaysia payable for every 1 MMb oe gross that the field produces above 10 MMboe gross and is capped at cumulative production of 27.5 MMboe gross. In calculating the present value of the asset retirement obligation provision, a blended discount rate of 6% (2025: 6%) per annum was used, based on a credit risk adjusted rate. The calculation also assumes that the costs are inflated by 2% a year (2025: 2%). The payment of these obligations is spread over a period of 60 years. 16. TRADE AND OTHER PAYABLES USD Thousands September 30, 2026 December 31, 2025 Trade payables 44,046 39,377 Joint operations creditors 1,913 2,198 Accrued expenses 126,973 101,353 Other 10,090 6,780 183,022 149,708 Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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19 17. 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, 2026 USD Thousands Total Financial assets at amortized cost Fair value recognized in profit or loss (FVTPL) Derivatives used for hedging Other assets1 34,376 34,376 – – Derivative instruments 8,570 – – 8,570 Joint operation debtors 1,464 1,464 – – Other current receivables2 119,721 119,721 – – Cash and cash equivalents 22,315 22,315 – – Financial assets 186,446 177,876 – 8,570 1 See Note 8 2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments. September 30, 2026 USD Thousands Total Financial liabilities at amortized cost Fair value recognized in profit or loss (FVTPL) Derivatives used for hedging Non-current financial liabilities 488,660 488,660 – – Derivative instruments 1,807 – – 1,807 Joint operation creditors 1,913 1,913 – – Other current liabilities 185,597 185,597 – – Financial liabilities 677,977 676,170 – 1,807 December 31, 2025 USD Thousands Total Financial assets at amortized cost Fair value recognized in profit or loss (FVTPL) Derivatives used for hedging Other assets1 34,545 34,545 – – Derivative instruments 2,929 – – 2,929 Joint operation debtors 2,292 2,292 – – Other current receivables2 90,902 84,198 6,704 – Cash and cash equivalents 7,037 7,037 – – Financial assets 137,705 128,072 6,704 2,929 1 See Note 8 2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments. December 31, 2025 USD Thousands Total Financial liabilities at amortized cost Fair value recognized in profit or loss (FVTPL) Derivatives used for hedging Non-current financial liabilities 481,033 481,033 – – Current financial liabilities 1,943 1,943 – – Derivative instruments 422 – – 422 Joint operation creditors 2,198 2,198 – – Other current liabilities 147,726 147,726 – – Financial liabilities 633,322 632,900 – 422 The carrying amount of the Group’s financial assets and liabilities approximate their fair values at the balance sheet dates. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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20 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, 2026 USD Thousands Level 1 Level 2 Level 3 Derivative instruments – current – 6,510 – Derivative instruments – non-current – 434 1,626 Financial assets – 6,944 1,626 Derivative instruments – current – 1,290 517 Derivative instruments – non-current – – – Financial liabilities – 1,290 517 December 31, 2025 USD Thousands Level 1 Level 2 Level 3 Other current receivables 6,704 – – Derivative instruments – current – 1,644 – Derivative instruments – non-current – – 1,285 Financial assets 6,704 1,644 1,285 Derivative instruments – current – – 422 Derivative instruments – non-current – – – Financial liabilities – – 422 The Group had oil price sale financial hedges outstanding as at September 30, 2026 which are summarized as follows: Period Volume (barrels per day) Type Average Pricing October 1, 2026 - December 31, 2026 5,000 WTI/WCS Differential USD -12.50/bbl October 1, 2026 - December 31, 2027 5,000 WCS (Hardisty to Houston)1 USD -7.55/bbl January 1, 2027 - December 31, 2027 5,000 WCS (Hardisty to Houston)1 USD -7.50/bbl October 1, 2026 - December 31, 2026 2,000 ARV2 USD -3.65/bbl 1 Represents the cost of transporting a barrel of WCS quality from Hardisty, Alberta to Houston, Texas. 2 Represents the difference in USD of a barrel of WCS quality in Houston against a barrel of WTI quality. The Group had gas price sale financial hedges outstanding as at September 30, 2026 which are summarized as follows: Period Volume (GJ per day) Type Average Pricing October 1, 2026 - October 31, 2026 15,000 AECO Gas Swap CAD 2.73/GJ The Group had electricity financial hedges outstanding as at September 30, 2026 which are summarized as follows: Period Volume (MW) Type Average Pricing October 1, 2026 - September 30, 2040 3 AESO CAD 75.00/MWh The Group entered into currency hedges to sell a total USD 120 million for the period January 2027 to December 2027 at an average rate of CAD 1.3842 (buy CAD). All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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21 18. CONTRACTUAL OBLIGATIONS AND COMMITMENTS In the normal course of business, the Group has committed to certain payments which are not recognized as liabilities. The following table summarizes the Group’s commitments in Canada as at September 30, 2026: CAD Millions 2026 2027 2028 2029 2030 Thereafter Transportation service1 15.6 85.6 99.5 100.8 101.7 1,355.0 Power2 3.1 12.4 9.8 - - - Total commitments 18.7 98.0 109.3 100.8 101.7 1,355.0 1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2046. 2 IPC has physical delivery power hedges to purchase 15MW at a weighted average price of CAD 74.92/MWh from October 1, 2026 to December 31, 2028, and an additional 5MW at a weighted average price of CAD 58.31/MWh from October 1, 2026 to December 31, 2027. 19. RELATED PARTIES The Group recognizes the following related parties: associated companies, jointly controlled entities, key management personnel and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or of its family or of any individual that controls, or has joint control or significant influence over the entity. All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with parties at arm’s length. During the first nine months of 2026, the Group has not entered into material transactions with related parties. 20. SUBSEQUENT EVENTS In October 2026, the Group entered into currency hedges to purchase: (i) a total EUR 15.6 million for the period January 2027 to October 2027 at an average rate of EUR 1.1432 (sell USD); (ii) a total MYR 72 million for the period January 2027 to October 2027 at an average rate of MYR 4.0331 (sell USD). Notes to the Interim Condensed Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025, UNAUDITED
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International Petroleum Corporation Suite 2800 1055 Dunsmuir Street Vancouver, British Columbia V7X 1L2, Canada Tel: +1 604 689 7842 E-mail: info@international-petroleum.com Web: international-petroleum.com□
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International Petroleum Corporation Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 3
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Contents Non-IFRS Measures References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA), “operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under IFRS Accounting Standards (“IFRS”) and do not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF, FCF, EBITDA, operating costs and net debt/ net cash that may be used by other public companies. Management believes that OCF, FCF, EBITDA, operating costs and net debt/net cash are useful supplemental measures that may assist shareholders and investors in assessing the cash generated by, and the financial performance and position of, the Corporation. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS measure is presented in this MD&A. See “Non-IFRS Measures” on page 18. 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 23. Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada and France/Malaysia are effective as of December 31, 2025, and are included in the reports prepared by Sproule International Limited and ERC Equipoise Ltd., respectively (collectively, Sproule ERCE), an independent qualified reserves evaluator and auditor, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule ERCE’s December 31, 2025, price forecasts. Certain abbreviations and technical terms used in this MD&A are defined or described under the heading “Other Supplementary Information”. INTRODUCTION 3 HIGHLIGHTS 4 OPERATIONS REVIEW 5 • Business Overview 5 • Operations Overview 7 FINANCIAL REVIEW 9 • Financial Results 9 • Capital Expenditure 17 • Financial Position and Liquidity 17 • Non-IFRS Measures 18 • Off-Balance Sheet Arrangements 20 • Outstanding Share Data 20 • Contractual Obligations and Commitments 21 • Material Accounting Policies and Estimates 21 • Transactions with Related Parties 21 • Financial Risk Management 22 RISK FACTORS 23 DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING 23 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 23 RESERVES AND RESOURCES ADVISORY 25 OTHER SUPPLEMENTARY INFORMATION 28 2
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 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 November 3, 2026 and is intended to provide an overview of the Group’s operations, financial performance and current and future business opportunities. This MD&A should be read in conjunction with IPC’s unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2026 as well as the audited consolidated financial statements and accompanying notes for the year ended December 31, 2025 (“Financial Statements”). Group Overview The Group is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development projects in Canada, Malaysia and France with exposure to growth opportunities. The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada, under the Business Corporations Act. The address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada. Basis of Preparation The MD&A and the Financial Statements have been prepared in accordance with IFRS Accounting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Financial information is presented in United States Dollars (“USD”). However, as the Group operates in Europe and in Canada, certain financial information prepared by subsidiaries has been reported in Euros (“EUR”) and in Canadian Dollars (“CAD”). In addition, certain costs relating to the operations in Malaysia, which are reported in USD, are incurred in Malaysian Ringgit (“MYR”). Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows: September 30, 2026 September 30, 2025 December 31, 2025 Average Period end Average Period end Average Year end 1 EUR equals USD 1.1616 1.1355 1.1180 1.1741 1.1293 1.1750 1 USD equals CAD 1.3851 1.4183 1.3993 1.3922 1.3975 1.3692 1 USD equals MYR 4.0108 4.0780 4.3265 4.2085 4.2791 4.0580 3
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 HIGHLIGHTS Q3 2026 Business Highlights • Average net production of approximately 44,000 barrels of oil equivalent per day (boepd) for the third quarter of 2026, in line with guidance for the period (56% heavy crude oil, 12% light and medium crude oil and 32% natural gas).(1) • Production ramp-up at Blackrod Phase 1 progressed according to plan in the third quarter after successfully achieving first oil in May 2026, ahead of schedule and on budget. • Sale of non-core asset in Canada completed in the third quarter for MCAD 70. • 1.1 million IPC common shares purchased and cancelled during Q3 2026 under the normal course issuer bid (NCIB). • IPC plans to seek Toronto Stock Exchange (TSX) approval for the renewal of the NCIB for the twelve month period commencing in early December 2026. Q3 2026 Financial Highlights • Operating costs per boe of USD 20.9 for Q3 2026, in line with guidance for the period. (3) • Operating cash flow (OCF) generation of MUSD 79 for Q3 2026. (3) • Capital and decommissioning expenditures of MUSD 37 for Q3 2026. • Free cash flow (FCF) generation for Q3 2026 amounted to MUSD 27. (3) • Net result of MUSD 60 for Q3 2026, including the gain on sale of assets in Canada during the quarter of MUSD 45. • Net debt of MUSD 473 as at September 30, 2026, down from MUSD 509 as at June 30, 2026. (3) Reserves and Resources • Total 2P reserves as at December 31, 2025 of 521 MMboe, with a reserve life index (RLI) of 31 years.(1)(2) • Contingent resources (best estimate, unrisked) as at December 31, 2025 of 1,224 MMboe. (1)(2) 2026 Annual Guidance • Full year 2026 average net production guidance range maintained at 44,000 to 47,000 boepd. (1) • Full year 2026 operating costs guidance range maintained at USD 18 to 20 per boe. (3) • Full year 2026 OCF revised guidance estimated at between MUSD 275 and 350 (assuming Brent USD 80 to 110 per barrel for the remainder of 2026) from previous guidance of between MUSD 230 and 330 (assuming Brent USD 70 to 90 per barrel). (3)(4) • Full year 2026 capital and decommissioning expenditures guidance forecast revised to MUSD 185, following the addition of capital activity at the producing assets. • Full year 2026 FCF revised guidance estimated at between MUSD 35 and 110 (assuming Brent USD 80 to 110 per barrel for the remainder of 2026) from previous guidance of between MUSD 10 and 110 (assuming Brent USD 70 to 90 per barrel). (3)(4) Three months ended September 30 Nine months ended September 30 USD Thousands 2026 2025 2026 2025 Revenue 211,955 172,297 570,703 509,681 Gross profit 52,333 32,066 127,602 99,878 Net result 59,901 3,802 82,580 33,883 Operating cash flow(3) 79,384 66,102 213,637 195,765 Free cash flow(3) 27,348 (23,083) 14,157 (124,507) EBITDA(3) 79,382 62,106 207,527 184,571 Net cash/(debt)(3) (472,809) (434,822) (472,809) (434,822) 4
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 OPERATIONS REVIEW Business Overview During the third quarter of 2026, benchmark international oil prices remained at elevated levels, with Brent oil prices averaging over USD 97 per barrel during the quarter. Market volatility continued during the quarter given the ongoing conflicts in the Middle East as well as uncertainties leading up to the fall midterm elections in the United States. The International Energy Agency (IEA) member countries’ strategic reserves release (SPR) continued during the quarter to attempt to alleviate some of the worldwide energy supply disruptions. As part of the SPR releases, G7 and IEA members also agreed to prioritize diesel fuel releases in order to combat high diesel prices, particularly in the US and Europe, which should add to the demand for heavy oil. The crude oil market remains tight and supported by geopolitical concerns over energy security. IPC retains full exposure to West Texas Intermediate (WTI) and Brent oil price upside with no hedges in place for these benchmark prices. The third quarter 2026 WTI to Western Canadian Select (WCS) price differential averaged approximately USD 14 per barrel, with the differential widening at the end of the third quarter and into the fourth quarter. The WTI to WCS differential remains sensitive to refinery demand for heavy crude on the US Gulf Coast and the availability of competing heavy crude supplies. IPC is well- positioned to partially mitigate the differential increase with 2026 full year WTI to WCS differential hedges for 5,000 bopd at USD -12.50 per barrel. In addition, IPC has hedged from July 2026 to December 2027, 5,000 bopd and from January 2027 to December 2027, a further 5,000 bopd of the differential between the WCS price in Hardisty, Canada and the WCS price in Houston, USA, effectively hedging the transportation cost between the locations, at USD -7.55 per barrel and USD -7.50 per barrel, respectively. In addition, 2,000 bopd of quality differential between the WCS in Houston and the WTI are hedged from July to December 2026 at USD -3.65 per barrel. The average Canadian gas benchmark price, AECO, was CAD 1.55 per Mcf for the third quarter of 2026, with gas demand during the summer months being typically lower than in colder months. The positive news for the Canadian gas market during the third quarter included closing of the acquisition by Shell of a large Canadian gas producer and the decision by the owners of LNG Canada to proceed with Phase 2 of that project. These strategic moves show international optimism on the strength and stability of the Canadian gas market which could benefit future Canadian gas prices. IPC implemented hedges for 15,000 GJ (approximately 14,500 Mcf) per day at CAD 2.73 per GJ (approximately CAD 2.84 per Mcf) from April to October 2026. Third Quarter 2026 Highlights and Full Year 2026 Guidance During the third quarter of 2026, IPC’s portfolio delivered average net production of 44,000 boepd, in line with the guidance for the quarter. The producing assets in Canada, Malaysia and France benefited from increased activity and strong oil commodity prices. IPC maintains the full year 2026 average net production guidance range of 44,000 to 47,000 boepd. (1) IPC’s operating costs per boe for the third quarter and the first nine months of 2026 were, respectively, USD 20.9 and USD 19.2, in line with guidance. Full year 2026 operating expenditure guidance of USD 18.0 to 20.0 per boe remains unchanged. (3) Operating cash flow (OCF) generation for the third quarter of 2026 was robust at USD 79 million. Full year 2026 OCF guidance is tightened to USD 275 to 350 million (assuming Brent USD 80 to 110 per barrel for the remainder of 2026). (3)(4) Capital and decommissioning expenditure for the third quarter of 2026 was USD 37 million. Full year 2026 capital and decommissioning expenditure is revised to USD 185 million, largely attributed to the addition of capital activity at the Canadian producing assets to take advantage of elevated commodity prices. Free cash flow (FCF) generation was USD 27 million during the third quarter of 2026, representing a seven times increase in FCF compared to the second quarter of 2026. As production continues to grow in Q4 2026 and into 2027, IPC is strongly positioned for increased FCF generation. Full year 2026 FCF guidance is modified to USD 35 to 110 million (assuming Brent USD 80 to 110 per barrel for the remainder of 2026). (3)(4) As at September 30, 2026, IPC’s net debt position was USD 473 million, from a net debt position of USD 509 million as at June 30, 2026. IPC’s net debt to trailing twelve-month EBITDA to end Q3 2026 is 1.8 times, after being above 2 times for the prior reporting periods in 2026. Rapid deleveraging is expected to continue in this high commodity price environment. (3) As previously announced, IPC has increased the facility size of its Canadian credit facility to approximately USD 250 million and extended the maturity of that facility to May 2028. IPC also previously announced the refinancing of its USD 450 million of unsecured bonds, with maturity in October 2030. This strong liquidity position, combined with the better than forecast cash flow generation in 2026, supports IPC in following through on its key strategic objectives to maximize stakeholder value. Stakeholder Returns: Normal Course Issuer Bid IPC renewed the current NCIB in December 2025, with the ability to repurchase up to approximately 6.5 million common shares up to early December 2026. Under the 2025/2026 NCIB, IPC repurchased and cancelled approximately 1.1 million common shares during the third quarter of 2026. The average price of common shares repurchased under the 2025/2026 NCIB during the third quarter was around SEK 234 / CAD 34 per share. 5
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 As at September 30, 2026, IPC had a total of 111,727,666 common shares issued and outstanding and IPC held no common shares in treasury. As at November 3, 2026, IPC had a total of 111,521,876 common shares issued and outstanding and IPC held no common shares in treasury. The IPC Board of Directors has approved, subject to acceptance by the Toronto Stock Exchange (TSX), the renewal of IPC’s NCIB for a further twelve months from December 2026 to early December 2027. We expect that the 2026/2027 NCIB will permit IPC to purchase through the TSX and Nasdaq Stockholm, and cancel, up to a further approximately 6.3 million IPC common shares, representing approximately 5.7% of the total current outstanding common shares (or 10% of IPC’s “public float” under applicable TSX rules). Blackrod The Blackrod asset is 100% owned by IPC and hosts the largest booked reserves and contingent resources within the IPC portfolio. Blackrod Phase 1 targets 30,000 bopd production through the newly commissioned Central Processing Facility (CPF) and contains 311 MMboe of 2P reserves, with the full Blackrod field having an additional 1,145 MMboe of 2C resources. (1)(2) As previously announced, first oil at Blackrod Phase 1 was successfully achieved at the end of May 2026, ahead of schedule and on budget (MUSD 855). During the third quarter, IPC successfully completed the first, and subsequently ongoing, oil sales from the Blackrod commercial plant in Edmonton, proving the effectiveness of the pipeline connected asset. The production ramp up progressed as planned during the third quarter, with current spot rates exceeding 10,000 bopd and early results indicating encouraging subsurface performance. At the time of this report, around 16 well pairs are currently on production, a further 14 are planned for conversion before year-end, and 10 well pairs are expected to be converted to production in early 2027. An incremental 6 sustaining well pairs were successfully drilled to take advantage of economies of scale and for redundancy. With excellent overall Phase 1 project delivery and initial performance, IPC has sanctioned incremental resource maturation works through seismic and stratigraphic well drilling outside of the initial development area planned to start in late Q4 2026. The low- cost resource conversion work is expected to allow for additional bookable reserves and positively position IPC for an eventual future phase expansion. In addition, IPC has sanctioned a butane blending project supported by robust economics through reduced condensate blending needs with completion expected by end 2027. Blackrod is a multi-generational asset that has been unlocked through the first phase of commercial development. More than 1.45 billion barrels of recoverable resource lies within the contiguous reservoir wholly owned by IPC. Future facilities expansion and phase development concepts continue to be matured by IPC. Blackrod has regulatory approval for up to 80,000 bopd. (1)(2) 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, 2025 (AIF) available on IPC’s website at www.international- petroleum.com and under IPC’s profile on SEDAR+ at www.sedarplus.ca. (2) See “Reserves and Resources Advisory“ below. Further information with respect to IPC’s reserves, contingent resources and estimates of future net revenue are described in the AIF . (3) Non-IFRS measures, see “Non-IFRS Measures” below and in the MD&A. (4) OCF and FCF forecasts at Brent USD 80 to 110 per barrel assume Brent to WTI differential of USD 5 to 10 per barrel and average WTI to WCS differential of USD 22 per barrel for the remainder of 2026. OCF and FCF forecasts assume gas price on average of approximately CAD 2.25 per Mcf for the remainder of 2026. 6
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Operations Overview Q3 2026 Overview In Q3 2026, IPC continued to demonstrate its commitment to operational excellence, delivering production performance and operating expenditure in line with IPC’s latest guidance. At the end of Q1 2026, supported by an improved pricing environment and strong operational performance, IPC increased its 2026 capital expenditure budget to enable additional production well drilling in France and Canada. By the end of Q3 2026, four new Basal Quartz production wells had been successfully drilled in the Suffield Area in Canada. All four wells are online and cleaning up, with initial production in line with expectations. In France, the four planned sidetrack wells at Fontaine-au-Bron and Villeperdue were drilled and brought online, with initial production in line with forecast. In response to continued strong commodity prices in Q3 2026, IPC accelerated the drilling of two additional infill production wells at Onion Lake Thermal in Canada. Both wells were drilled during the quarter and are expected to be brought online late in Q4 2026. At Blackrod Phase 1, the production ramp-up continued during Q3 2026. By the end of the quarter, 12 well pairs had been converted and brought on to oil production, with further well pair conversions ongoing. Production increased through the quarter, and a further step-up is expected during Q4 2026 as additional well pairs are converted and brought online. Reserves and Resources The total 2P reserves attributable to IPC’s oil and gas assets are 521 MMboe as at December 31, 2025, as certified by IPC’s independent third-party reserve auditor and evaluator. The 2P reserve life index (RLI) as at December 31, 2025, is approximately 31 years. Best estimate contingent resources as at December 31, 2025, are 1,224 MMboe (unrisked). See “Reserves and Resources Advisory” below. Production Average daily net production for Q3 2026 was 44.0 Mboepd, in line with IPC’s latest quarterly guidance. This performance was supported by strong production from the Canadian assets, the continued production ramp-up of Blackrod Phase 1, and better-than- forecast production in France. IPC remains well positioned to deliver full-year average net production within the guidance range of 44,000 to 47,000 boepd, supported by strong operational performance during the first nine months of 2026 and the continued production ramp-up at Blackrod Phase 1. The production during Q3 2026 and the first nine months of 2026 with comparatives is summarized below: Production in Mboepd Three months ended September 30 Nine months ended September 30 Year ended December 31 2026 2025 2026 2025 2025 Crude oil Canada – Northern Assets 17.0 15.8 15.3 14.5 14.7 Canada – Southern Assets 8.4 9.9 8.8 10.4 10.2 Malaysia 2.4 3.2 2.9 2.8 3.0 France 2.3 2.1 2.0 2.1 2.1 Total crude oil production 30.1 31.0 29.0 29.8 30.0 Gas Canada – Northern Assets 0.4 0.5 0.4 0.4 0.4 Canada – Southern Assets 13.5 14.4 13.7 14.4 14.5 Total gas production 13.9 14.9 14.1 14.8 14.9 Total production 44.0 45.9 43.1 44.6 44.9 Quantity in MMboe 4.04 4.22 11.75 12.19 16.38 See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”. 7
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 CANADA Production in Mboepd Working Interest (WI) Three months ended September 30 Nine months ended September 30 Year ended December 31 2026 2025 2026 2025 2025 - Oil Onion Lake Thermal 100% 10.6 13.1 11.3 12.0 12.2 - Oil Suffield Area 100% 7.6 8.7 7.9 9.0 8.9 - Oil Blackrod 100% 5.1 – 2.3 – – - Oil Other 50-100% 2.1 3.9 2.6 3.9 3.8 - Gas ~100% 13.9 14.9 14.1 14.8 14.9 Canada 39.3 40.6 38.2 39.7 39.8 Production Net production from IPC’s assets in Canada during Q3 2026 was in line with guidance at 39.3 Mboepd with stable operational performance at the major oil and gas producing assets. Organic Growth and Capital Projects During Q3 2026, IPC increased capital activity in Canada to take advantage of the strong commodity price environment. IPC drilled two additional infill production wells at Onion Lake Thermal during the quarter. The wells are expected to be brought online in late Q4 2026. In the Suffield Area, drilling of four Basal Quartz production wells was completed during Q3 2026. The wells are cleaning up, with initial production results in line with expectations. At Blackrod Phase 1, construction and commissioning activities have been completed. During Q3 2026, the production and injection well pairs continued warming through steam circulation, and seven additional well pairs were converted to production, bringing the total to 12 wells on production by quarter-end. At the time of this report, there were 16 well pairs converted to production. Initial production is in line with expectations, and rates are expected to increase during the final quarter of 2026. Plateau production of 30,000 bopd is forecast to be achieved by the end of 2027. MALAYSIA Production in Mboepd WI Three months ended September 30 Nine months ended September 30 Year ended December 31 2026 2025 2026 2025 2025 Bertam 100% 2.4 3.2 2.9 2.8 3.0 Production Net production in Malaysia during Q3 2026 was 2.4 Mboepd, below guidance, due to well A16 being shut in following an Electrical Submersible Pump (ESP) failure. Operational Projects Planning and scheduling of the Bertam A16 production well maintenance is being progressed. FRANCE Production in Mboepd WI Three months ended September 30 Nine months ended September 30 Year ended December 31 2026 2025 2026 2025 2025 France 35–100%1 2.3 2.1 2.0 2.1 2.1 1 In Q2 2026, IPC entered into an asset exchange agreement relating to certain fields in the Paris Basin and the Aquitaine Basin. Completion of the asset exchange remains subject to regulatory approval. Production Net production in France during Q3 2026 was ahead of guidance at 2.3 Mboepd. Organic Growth In France, drilling of three sidetrack wells at Fontaine-au-Bron and one at Villeperdue commenced in Q2 2026, with all four wells completed by the end of Q3 2026. The four wells are online and undergoing clean up, with initial production results in line with expectations. 8
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 FINANCIAL REVIEW Financial Results Selected Interim Financial Information Selected consolidated statement of operations is as follows: USD Thousands Q3-26 Q2-26 Q1-26 Q4-25 Q3-25 Q2-25 Q1-25 Q4-24 Revenue 211,955 185,738 173,010 176,207 172,297 158,892 178,492 199,124 Gross profit 52,333 38,094 37,175 28,242 32,066 23,663 44,149 42,774 Net result 59,901 9,917 12,762 (4,942) 3,802 13,850 16,231 415 Earnings per share – USD 0.53 0.09 0.11 (0.04) 0.03 0.12 0.14 0.00 Earnings per share fully diluted – USD 0.52 0.09 0.11 (0.04) 0.03 0.12 0.13 0.00 Operating cash flow1 79,384 66,518 67,735 63,138 66,102 54,873 74,790 78,158 Free cash flow1 27,348 3,895 (17,086) (28,627) (23,083) (58,252) (43,172) (61,476) EBITDA1 79,382 63,856 64,289 58,966 62,106 51,519 70,946 76,184 Net cash/(debt) at period end1 (472,809) (508,999) (513,413) (483,615) (434,822) (374,977) (314,255) (208,528) 1 See definition on page 18 under “Non-IFRS measures” Summarized consolidated balance sheet information is as follows: USD Thousands September 30, 2026 December 31, 2025 Non-current assets 1,847,103 1,847,327 Current assets 210,965 130,302 Total assets 2,058,068 1,977,629 Total non-current liabilities 917,020 890,204 Current liabilities 194,413 160,248 Total liabilities 1,111,433 1,050,452 Net assets 946,635 927,177 Working capital (including cash) 16,552 (29,946) 9
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 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 and Blackrod assets) and (ii) Canada – Southern Assets (comprised mainly of the Suffield area assets). This is consistent with the internal reporting provided to the CEO, who is the chief operating decision maker. The following tables present certain segment information. Three months ended – September 30, 2026 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 129,479 58,921 23,051 19,560 – 231,011 Gas and NGLs 63 7,929 – – – 7,992 Net sales of oil and gas 129,542 66,850 23,051 19,560 – 239,003 Change in under/over lift position – – – 37 – 37 Royalties (18,350) (10,765) – (1,173) – (30,288) Hedging settlement 256 2,628 – – – 2,884 Other operating revenue – – – 170 149 319 Revenue 111,448 58,713 23,051 18,594 149 211,955 Operating costs (33,043) (29,138) (12,875) (9,529) – (84,585) Cost of blending (38,749) (5,187) – – – (43,936) Change in inventory position (1,495) 216 545 495 – (239) Depletion (11,367) (11,149) (4,440) (3,472) – (30,428) Exploration and business development costs – – – – (434) (434) Gross profit/(loss) 26,794 13,455 6,281 6,088 (285) 52,333 Three months ended – September 30, 2025 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 99,686 54,768 15,581 11,870 – 181,905 Gas and NGLs 25 4,782 – – – 4,807 Net sales of oil and gas 99,711 59,550 15,581 11,870 – 186,712 Change in under/over lift position – – – 1,585 – 1,585 Royalties (14,269) (7,672) – (931) – (22,872) Hedging settlement 1,886 4,701 – – – 6,587 Other operating revenue – – – 197 88 285 Revenue 87,328 56,579 15,581 12,721 88 172,297 Operating costs (22,707) (33,758) (10,908) (8,254) – (75,627) Cost of blending (27,588) (4,863) – – – (32,451) Change in inventory position (26) (353) 2,327 (253) – 1,695 Depletion (10,360) (12,425) (6,504) (2,956) – (32,245) Depreciation of other assets – – (1,419) – – (1,419) Exploration and business development costs – – – – (184) (184) Gross profit/(loss) 26,647 5,180 (923) 1,258 (96) 32,066 10
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Nine months ended – September 30, 2026 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 355,505 180,513 70,132 57,232 – 663,382 Gas and NGLs 228 29,233 – – – 29,461 Net sales of oil and gas 355,733 209,746 70,132 57,232 – 692,843 Change in under/over lift position – – - (4,707) – (4,707) Royalties (50,359) (28,059) - (2,906) – (81,324) Hedging settlement (24,936) (12,037) – – – (36,973) Other operating revenue – – – 536 328 864 Revenue 280,438 169,650 70,132 50,155 328 570,703 Operating costs (74,144) (86,984) (37,316) (27,818) – (226,262) Cost of blending (113,354) (17,037) – – – (130,391) Change in inventory position (632) 230 4,569 554 – 4,721 Depletion (29,252) (34,542) (16,007) (9,360) – (89,161) Exploration and business development costs – – – – (2,008) (2,008) Gross profit/(loss) 63,056 31,317 21,378 13,531 (1,680) 127,602 Nine months ended – September 30, 2025 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other Total Crude oil 283,855 172,623 42,785 36,147 – 535,410 Gas and NGLs 204 26,335 – – – 26,539 Net sales of oil and gas 284,059 198,958 42,785 36,147 – 561,949 Change in under/over lift position – – – 4,285 – 4,285 Royalties (39,321) (26,293) – (2,503) – (68,117) Hedging settlement 3,279 7,467 – – – 10,746 Other operating revenue – – – 572 246 818 Revenue 248,017 180,132 42,785 38,501 246 509,681 Operating costs (61,673) (97,583) (31,257) (24,789) – (215,302) Cost of blending (87,265) (16,181) – – – (103,446) Change in inventory position 143 (509) 5,869 (427) – 5,076 Depletion (28,042) (37,379) (17,146) (8,015) – (90,582) Depreciation of other assets – – (4,797) – – (4,797) Exploration and business development costs – – – – (752) (752) Gross profit/(loss) 71,180 28,480 (4,546) 5,270 (506) 99,878 11
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Three and nine months ended September 30, 2026 Review Revenue Total revenue amounted to USD 211,955 thousand for Q3 2026, compared to USD 172,297 thousand for Q3 2025 and USD 570,703 thousand for the first nine months of 2026 compared to USD 509,681 thousand for the first nine months of 2025 is analyzed as follows: USD Thousands Three months ended September 30 Nine months ended September 30 2026 2025 2026 2025 Crude oil sales 231,011 181,905 663,382 535,410 Gas and NGL sales 7,992 4,807 29,461 26,539 Change in under/overlift position 37 1,585 (4,707) 4,285 Royalties (30,288) (22,872) (81,324) (68,117) Hedging settlement 2,884 6,587 (36,973) 10,746 Other operating revenue 319 285 864 818 Revenue 211,955 172,297 570,703 509,681 The main components of revenue for the three and nine months ended September 30, 2026 and September 30, 2025, respectively, are detailed below. Crude oil sales Three months ended – September 30, 2026 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 129,479 58,921 23,051 19,560 231,011 - Quantity sold in bbls 1,842,758 825,435 181,683 201,552 3,051,428 - Average price realized USD per bbl 70.26 71.38 126.87 97.05 75.71 Three months ended – September 30, 2025 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 99,686 54,768 15,581 11,870 181,905 - Quantity sold in bbls 1,849,991 993,748 209,107 170,751 3,223,597 - Average price realized USD per bbl 53.88 55.11 74.51 69.52 56.43 Crude oil revenue was 27% higher in Q3 2026 compared to Q3 2025 due to higher oil prices. The Suffield area assets, Onion Lake Thermal and Blackrod crude oil in Canada is blended with purchased condensate diluent volumes to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for Canada. The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to West Texas Intermediate (“WTI”). For Q3 2026, WTI averaged USD 86 per bbl compared to USD 65 per bbl for Q3 2025 and the average discount to WCS used in IPC’s pricing formula was USD 14 per bbl compared to USD 10 per bbl for the comparative period in 2025. The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia during Q3 2026 and one cargo lifting in Q3 2025. Produced unsold oil barrels from Bertam at the end of Q3 2026 amounted to 139,000 bbls, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 97 per bbl for Q3 2026 compared to USD 69 per bbl for the comparative period. 12
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Nine months ended – September 30, 2026 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 355,505 180,513 70,132 57,232 663,382 - Quantity sold in bbls 5,220,034 2,601,777 621,901 649,218 9,092,930 - Average price realized USD per bbl 68.10 69.38 112.77 88.16 72.96 Nine months ended – September 30, 2025 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Crude oil sales - Revenue in USD thousands 283,855 172,623 42,785 36,147 535,410 - Quantity sold in bbls 5,153,175 3,086,686 580,067 507,167 9,327,095 - Average price realized USD per bbl 55.08 55.93 73.76 71.27 57.40 The Suffield area assets, Onion Lake and Blackrod 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 higher by 24% during the first nine months of 2026 compared to the first nine months of 2025 due to higher oil prices. The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. For the first nine months of 2026, WTI averaged USD 83 per bbl compared to USD 67 per bbl for the comparative period and the average discount to WCS used in IPC’s pricing formula was USD 14 per bbl compared to USD 11 per bbl for the comparative period. The realized sales price for Malaysia and France is based on Dated Brent crude oil prices and the average market Brent crude oil price was USD 94 per bbl for the first nine months of 2026 compared to USD 71 per bbl for the comparative period. Gas and NGL sales Three months ended – September 30, 2026 Canada – Northern Assets Canada – Southern Assets Total Gas and NGL sales - Revenue in USD thousands 63 7,929 7,992 - Quantity sold in Mcf 64,840 6,905,840 6,970,680 - Average price realized USD per Mcf 0.97 1.15 1.15 Three months ended – September 30, 2025 Canada – Northern Assets Canada – Southern Assets Total Gas and NGL sales - Revenue in USD thousands 25 4,782 4,807 - Quantity sold in Mcf 69,170 7,404,566 7,473,736 - Average price realized USD per Mcf 0.37 0.65 0.64 Gas and NGL sales revenue was 66% higher for the Q3 2026 compared to Q3 2025, mainly due to higher gas prices achieved. IPC’s achieved gas price is based on AECO pricing plus a premium. For Q3 2026, IPC realized an average price of CAD 1.58 per Mcf compared to AECO average pricing of CAD 1.55 per Mcf. 13
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Nine months ended – September 30, 2026 Canada – Northern Assets Canada – Southern Assets Total Gas and NGL sales - Revenue in USD thousands 228 29,233 29,461 - Quantity sold in Mcf 205,299 20,430,026 20,635,325 - Average price realized USD per Mcf 1.11 1.43 1.43 Nine months ended – September 30, 2025 Canada – Northern Assets Canada – Southern Assets Total Gas and NGL sales - Revenue in USD thousands 204 26,335 26,539 - Quantity sold in Mcf 212,242 21,611,998 21,824,240 - Average price realized USD per Mcf 0.96 1.22 1.22 Gas and NGL sales revenue was 11% higher for the first nine months of 2026 compared to the first nine months of 2025, mainly due to higher gas prices achieved. IPC’s achieved gas price is based on AECO pricing plus a premium. For the first nine months of 2026, IPC realized an average price of CAD 1.94 per Mcf compared to AECO average pricing of CAD 1.71 per Mcf. Hedging settlement IPC enters into oil and gas prices risk management contracts in order to ensure a certain level of cash flow. It focuses mainly on oil and gas price swaps and on collars to a lesser extent, to mitigate these commodities price exposure. Oil and gas hedging contracts are not entered into for speculative purposes and only account for a portion of IPC’s production. The realized hedging settlement for Q3 2026 amounted to a gain of USD 2,884 thousand, and a loss for the first nine months of 2026 of USD 36,973 thousand which consisted of a loss of USD 39,388 thousand on the oil contracts and a gain of USD 2,415 thousand on the gas contracts. Also see the Financial Position and Liquidity and the Financial Risk Management sections below. Production costs Production costs including inventory movements amounted to USD 128,760 thousand for Q3 2026 compared to USD 106,383 thousand for Q3 2025 and USD 351,932 thousand for the first nine months of 2026 compared to the USD 313,672 thousand for the first nine months of 2025, and is analyzed as follows: Three months ended – September 30, 2026 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other3 Total Operating costs1 33,043 29,138 12,875 9,529 – 84,585 USD/boe2 20.59 14.48 58.98 45.59 n/a 20.91 Cost of blending 38,749 5,187 – – – 43,936 Change in inventory position 1,495 (216) (545) (495) – 239 Production costs 73,287 34,109 12,330 9,034 – 128,760 14
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Three months ended – September 30, 2025 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other3 Total Operating costs1 22,707 33,758 10,908 8,254 – 75,627 USD/boe2 15.16 15.10 37.44 41.54 n/a 17.91 Cost of blending 27,588 4,863 – – – 32,451 Change in inventory position 26 353 (2,327) 253 – (1,695) Production costs 50,321 38,974 8,581 8,507 – 106,383 Nine months ended – September 30, 2026 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other3 Total Operating costs1 74,144 86,984 37,316 27,818 – 226,262 USD/boe2 17.31 14.12 47.42 50.51 n/a 19.25 Cost of blending 113,354 17,037 – – – 130,391 Change in inventory position 632 (230) (4,569) (554) – (4,721) Production costs 188,130 103,791 32,747 27,264 – 351,932 Nine months ended – September 30, 2025 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Other3 Total Operating costs1 61,673 97,583 34,785 24,789 (3,528) 215,302 USD/boe2 15.15 14.12 45.28 42.33 n/a 17.66 Cost of blending 87,265 16,181 – – – 103,446 Change in inventory position (143) 509 (5,869) 427 – (5,076) Production costs 148,795 114,273 28,916 25,216 (3,528) 313,672 1 See definition on page 18 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 current period and for 2025. 3 Included in the Malaysia operating costs to Q3 2025 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 40.69 for the nine months ended September 30, 2025. Operating costs Operating costs amounted to USD 84,585 thousand for Q3 2026 compared to USD 75,627 thousand for Q3 2025 and amounted to USD 226,262 thousand for the first nine months of 2026 compared to USD 215,302 thousand for the comparative period. Operating costs per boe amounted to USD 20.91 per boe in Q3 2026 in line with the guidance for the quarter compared with USD 17.91 per boe in Q3 2025. At Blackrod Phase 1, the production ramp-up continued during Q3 2026. Plateau production of 30,000 bopd is forecast to be achieved by the end of 2027. During ramp-up of SAGD projects, operating and transportation costs are largely fixed in nature regardless of production volumes. IPC anticipates that operating cost per barrel from Blackrod Phase 1 will materially decrease as production increases. Operating costs per boe in Malaysia increased in Q3 2026 compared to Q3 2025 due to well maintenance in Q3 2026 and lower production. Cost of blending For the Suffield area, Onion Lake Thermal and Blackrod assets in Canada, oil production is blended with purchased diluent to meet pipeline specifications. As a result of the blending, actual sales volumes are higher than produced barrels and the realized sales price of a blended barrel is higher than an unblended barrel. The cost of the diluent amounted to USD 43,936 thousand for Q3 2026 compared to USD 32,451 thousand for Q3 2025 due to higher prices. 15
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 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 2026, IPC had crude entitlement of 139,000 bbls of oil on the FPSO Bertam facility being crude produced but not yet sold. Depletion costs The total depletion and decommissioning costs amounted to USD 30,428 thousand for Q3 2026 compared to USD 32,245 thousand for Q3 2025. The depletion charge is analyzed in the following tables: Three months ended – September 30, 2026 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Depletion cost in USD thousands 11,367 11,149 4,440 3,472 30,428 USD per boe 7.08 5.54 20.34 16.61 7.52 Three months ended – September 30, 2025 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Depletion cost in USD thousands 10,360 12,425 6,504 2,956 32,245 USD per boe 6.92 5.56 22.32 14.89 7.64 Nine months ended – September 30, 2026 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Depletion cost in USD thousands 29,252 34,542 16,007 9,360 89,161 USD per boe1 6.83 5.63 20.34 17.00 7.59 Nine months ended – September 30, 2025 USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Depletion cost in USD thousands 28,042 37,379 17,146 8,015 90,582 USD per boe1 6.89 5.52 22.32 13.69 7.43 1 USD/boe in the tables above is calculated by dividing the depletion cost by the production volume for each country for the period. The depletion charge is derived by applying the depletion rate per boe to the volumes produced in the period by each field. Depreciation of other tangible fixed assets The total depreciation of other tangible fixed assets amounted to nil for Q3 2026 compared to USD 1,419 thousand for Q3 2025. In 2025, the depreciation relates to FPSO Bertam, which has been depreciated to its residual value by the end of 2025. Exploration and business development costs The total exploration and business development costs amounted to a cost of USD 2,008 thousand for the first nine months of 2026 and USD 752 thousand for the first nine months of 2025. Net financial items Net financial items amounted to a charge of USD 12,541 thousand for Q3 2026, compared to a charge of USD 21,030 thousand for Q3 2025, and a charge of USD 55,663 thousand for the first nine months of 2026 compared to a charge of USD 39,726 thousand for the first nine months of 2025, and included no realized currency hedge loss and a net foreign exchange loss of USD 11,579 thousand for the first nine months of 2026 and compared to a realized currency hedge loss and a net foreign exchange gain of respectively USD 8,039 thousand and USD 8,502 thousand for the first nine months of 2025. The foreign exchange movements are mainly resulting from the revaluation of intra-group loan funding balances. Excluding foreign exchange movements and realized currency cashflow hedges, the net financial items amounted to a charge of USD 14,714 thousand for Q3 2026, compared to a charge of USD 14,778 thousand for Q3 2025 and a charge of USD 44,084 thousand for the first nine months of 2026 compared to a charge of USD 40,189 thousand for the first nine months of 2025. 16
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 The interest expense amounted to USD 9,924 thousand for Q3 2026, compared to USD 10,082 thousand for the comparative period in 2025 and USD 29,535 thousand for the first nine months of 2026 compared to USD 27,823 thousand for the first nine months of 2025, and mainly related to the bond interest at a fixed coupon rate of 7.5% per annum (former bonds in 2025 were bearing a fixed coupon rate of 7.25% per annum). The unwinding of the asset retirement obligation discount rate amounted to USD 4,079 thousand for Q3 2026 compared to USD 4,229 thousand for Q3 2025 and USD 12,364 thousand for the first nine months of 2026 compared to USD 12,301 thousand for the first nine months of 2025. Income tax The corporate income tax amounted to a charge of USD 20,886 thousand for Q3 2026 compared to a charge of USD 3,030 thousand for Q3 2025 and a charge of USD 28,417 thousand for the first nine months of 2026 compared to a charge of USD 13,876 thousand for the comparative period. The current income tax amounted to a charge of USD 4,019 thousand for Q3 2026 and a charge of USD 5,687 thousand for the first nine months of 2026 and mainly related to Malaysia and France. No corporate income tax is expected to be payable in Canada in 2026 due to the usage of historical tax pools. Capital Expenditure Development and exploration and evaluation expenditures incurred during the first nine months of 2026 were as follows: USD Thousands Canada – Northern Assets Canada – Southern Assets Malaysia France Total Development 113,017 15,804 1,993 21,956 152,770 Exploration and evaluation 1,915 – – – 1,915 114,932 15,804 1,993 21,956 154,685 Capital expenditures during the period were mainly spent in Canada on the Blackrod Phase 1 development project and in France on oil well drilling operations. Other tangible fixed assets Other tangible fixed assets amounted to USD 11,392 thousand as at September 30, 2026, which included USD 9,200 thousand in respect of the FPSO Bertam. The FPSO Bertam has been depreciated to its residual value. Financial Position and Liquidity Financing As at January 1, 2025, IPC had USD 450 million of senior unsecured bonds outstanding, maturing in February 2027 with a fixed coupon rate of 7.25% per annum. In October 2025, IPC completed the issuance of USD 450 million of new senior unsecured bonds, maturing in October 2030 with a fixed coupon rate of 7.50% per annum, payable in semi-annual instalments in April and October, and with semi-annual amortizations of USD 25 million commencing in April 2028. The proceeds of the new bonds were used to fully redeem and cancel the previous bonds. The bond repayment obligations as at September 30, 2026, are classified as non-current as there are no mandatory repayments within the next twelve months. In addition, as at September 30, 2026, the Group had a senior secured revolving credit facility of CAD 348.5 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada, with a maturity date in May 2028. As at September 30, 2026, CAD 64 million (approximately USD 45 million) was drawn under the Canadian RCF . As at September 30, 2026, the Group also had a letter of credit facility in Canada (the “LC Facility”). As at September 30, 2026, operational letters of credit in an aggregate of CAD 11.9 million have been issued under the LC Facility. The Group is in compliance with the covenants of the bonds and its financing facilities as at September 30, 2026. Net debt as at September 30, 2026 amounted to USD 473 million. Cash and cash equivalents held amounted to USD 22 million as at September 30, 2026. IPC intends to fund remaining budgeted capital expenditures in 2026 with forecast cash flow generated by its operations, cash on hand and, if required, Canadian RCF loan drawing. Working Capital As at September 30, 2026, the Group had a working capital balance including cash of USD 16,552 thousand compared to negative USD 29,946 thousand as at December 31, 2025. 17
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Non-IFRS Measures In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by, and the financial performance and condition of, the Corporation. Management also uses non-IFRS measures internally in order to facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures are important supplemental measures of operating performance because they highlight trends in the core business that may not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties frequently use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the purpose of presenting information about management’s current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. “Operating cash flow” is calculated as revenue less production costs including net sales of diluent less current tax. Operating cash flow is used to analyze the amount of cash that is being generated available for capital investment and servicing debt. “Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures less general and administrative expenses before depreciation and less cash financial items. Free cash flow is used to analyze the amount of cash that is being generated by the business and that is available for such purposes as repaying debt, funding acquisitions and returning capital to shareholders. “EBITDA” is calculated as net result before financial items, taxes, depletion and decommissioning costs, exploration and business development costs, impairment costs and depreciation and before non-recurring profit/loss on sale of assets and other income. “Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is used to analyze the cash cost of producing the oil and gas volumes. “Net debt” is calculated as bank loans and bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash equivalents less bank loans and bonds. Reconciliation of Non-IFRS Measures Operating cash flow The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements: USD Thousands Three months ended September 30 Nine months ended September 30 2026 2025 2026 2025 Revenue 211,955 172,297 570,703 509,681 Production costs and net sales of diluent to third party1 (128,552) (106,292) (351,379) (313,162) Current tax (4,019) 97 (5,687) (754) Operating cash flow 79,384 66,102 213,637 195,765 1 Includes net sales of diluent to third parties amounting to USD 208 thousand for the three months ended September 30, 2026 and USD 553 thousand for the first nine months of 2026 18
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 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 2026 2025 2026 2025 Operating cash flow - see above 79,384 66,102 213,637 195,765 Capital expenditures (36,026) (80,128) (154,685) (276,939) Abandonment and farm-in expenditures1 (1,930) 5,374 (2,978) 2,956 General and administrative expenses before depreciation2 (4,021) (3,899) (11,797) (11,948) Cash financial items3 (10,059) (10,532) (30,020) (34,341) Free cash flow 27,348 (23,083) 14,157 (124,507) 1 See note 15 to the Financial Statements. 2 Depreciation is not specifically disclosed in the Financial Statements. 3 See note 4 to the Financial Statements. EBITDA The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA: USD Thousands Three months ended September 30 Nine months ended September 30 2026 2025 2026 2025 Net result 59,901 3,802 82,580 33,883 Net financial items 12,541 21,030 55,663 39,726 Income tax 20,886 3,030 28,417 13,876 Depletion and decommissioning costs 30,428 32,245 89,161 90,582 Depreciation of other tangible fixed assets – 1,419 – 4,797 Exploration and business development costs 434 184 2,008 752 Sale of assets (45,230) – (51,451) (104) Depreciation included in general and administrative expenses1 422 396 1,149 1,059 EBITDA 79,382 62,106 207,527 184,571 1 Item is not shown in the Financial Statements. Operating costs The following table sets out how operating costs is calculated: USD Thousands Three months ended September 30 Nine months ended September 30 2026 2025 2026 2025 Production costs 128,760 106,383 351,932 313,672 Cost of blending (43,936) (32,451) (130,391) (103,446) Change in inventory position (239) 1,695 4,721 5,076 Operating costs 84,585 75,627 226,262 215,302 19
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Net cash/(debt) The following table sets out how net cash/(debt) is calculated: USD Thousands September 30, 2026 December 31, 2025 Bank loans (45,124) (40,652) Bonds (450,000) (450,000) Cash and cash equivalents 22,315 7,037 Net cash/(debt) (472,809) (483,615) Off-Balance Sheet Arrangements IPC, through its subsidiary IPC Canada Ltd, had issued five letters of credit as at September 30, 2026 as follows: (a) MCAD 1.0 in respect of its obligations related to the Ferguson asset; (b) MCAD 1.3 in respect of pipeline access; (c) MCAD 0.5 in respect of the hedging of electricity prices; (d) MCAD 3.9 in respect of electricity distribution services; and (e) MCAD 5.3 in respect of the land acquisition completed in October 2025. 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, 2025, IPC had a total of 119,169,471 common shares issued and outstanding, of which 110,156 common shares were held in treasury. Over the period of January 1, 2025 to December 4, 2025, IPC purchased and cancelled 6,641,970 common shares under the normal course issuer bid (NCIB) and 261,818 common shares under certain other exemptions in Canada. As at December 31, 2025, IPC had a total of 112,155,527 common shares issued and outstanding, with no common shares held in treasury. In February 2026, IPC issued 671,225 common shares in connection with the vesting of previously issued IPC Share Unit Plan awards. During the first nine months of 2026, IPC purchased and cancelled a total of 1,099,086 shares under the NCIB. The average price of common shares purchased during the first nine months of 2026 was SEK 234 / CAD 34. As at September 30, 2026, IPC had a total of 111,727,666 common shares issued and outstanding, with no common shares held in treasury. As at November 3, 2026, IPC had a total of 111,521,876 common shares issued and outstanding, with no common shares held in treasury. Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 42,597,533 common shares in IPC, representing 38.1% of the outstanding common shares as at September 30, 2026. In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on matters to be decided by the holders of IPC’s common shares. IPC has 2,569,447 IPC Share Unit Plan awards outstanding as at November 3, 2026 of which 791,096 awards were granted in 2026. The Corporation is authorized to issue an unlimited number of common shares without par value. The Corporation is also authorized to issue an unlimited number of class A preferred shares and an unlimited number of class B preferred shares, issuable in series. 20
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Contractual Obligations and Commitments In the normal course of business, the Group has committed to certain payments which are not recognized as liabilities. The following table summarizes the Group’s commitments in Canada as at September 30, 2026: MCAD 2026 2027 2028 2029 2030 Thereafter Transportation service1 15.6 85.6 99.5 100.8 101.7 1,355.0 Power2 3.1 12.4 9.8 – – – Total commitments 18.7 98.0 109.3 100.8 101.7 1,355.0 1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2046. 2 IPC has physical delivery power hedges to purchase 15MW at a weighted average price of CAD 74.92/MWh from October 1, 2026 to December 31, 2028, and an additional 5MW at a weighted average price of CAD 58.31/MWh from October 1, 2026 to December 31, 2027. Material 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. Management believes the following critical accounting policies affect the more significant judgments and estimates used in the preparation of the consolidated financial statements: Oil and gas reserves, impairment and asset retirement obligations The accounting for oil and gas assets requires significant estimates and judgements, particularly in relation to reserves, impairment and asset retirement obligations. Estimates of proved and probable oil and gas reserves, prepared using standard recognized evaluation techniques and reviewed by independent qualified reserves auditors, are fundamental to impairment testing, depletion calculations under the unit of production method, and the timing and measurement of asset retirement obligations. These estimates are based on management’s assumptions regarding expected production volumes, future oil and gas prices, development and production costs, and economic factors such as oil price and inflation. Impairment tests are performed when there are indicators of impairment. Key assumptions in the impairment models include oil and gas reserve estimates, forward price curves, long-term cost assumptions and the discount rate, all of which are subject to change as new information becomes available or economic conditions evolve. Provisions for asset retirement obligations are based on estimates of future decommissioning and restoration costs, reflecting current legal and constructive requirements, available technology and prevailing price levels. Actual cash outflows may differ from estimates due to changes in legislation, technical requirements or cost levels, and therefore these provisions are reviewed on a regular basis. Deferred income tax assets The Group accounts for differences that arise between the carrying amount of assets and liabilities and their tax bases in accordance with IAS 12, Income Taxes, which requires deferred income tax assets only to be recognized to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilized. Management estimates future taxable profits based on the financial models used to value its oil and gas properties. Any change to the estimates and assumptions used for the key operational and financial variables used within the business models could affect the amount of deferred income tax assets recognized. The effects of changes in estimates do not give rise to prior year adjustments and are treated prospectively over the estimated remaining commercial reserves of each field. While the Group uses its best estimates and judgement, actual results could differ from these estimates. Transactions with Related Parties The Group recognizes the following related parties: associated companies, jointly controlled entities, key management personnel and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or of its family or of any individual that controls, or has joint control or significant influence over the entity. All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with parties at arm’s length. During the first nine months of 2026, the Group has not entered into material transactions with related parties. 21
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 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 risk 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, 2026, the Group had entered into oil, gas, currency and electricity hedges – see below. Management believes that the cash resources, other current assets and cash flow from operations are sufficient to finance the Group’s operations and capital expenditures program over the next year. Capital Management The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its committed financial liabilities and work program requirements in order to create shareholder value. The Group may put in place new bonds or credit facilities, repay debt, or pursue other such restructuring activities as appropriate. Management of the Corporation will continuously monitor and manage the Group’s capital, liquidity and net debt position in order to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility. Price of Oil and Gas Prices of oil and gas are affected by the normal economic drivers of supply and demand as well as by financial investors and market uncertainty. Factors that influence these prices include operational decisions, prices of competing fuels, natural disasters, economic conditions, transportation constraints, political instability or conflicts or actions by major oil exporting countries. Price fluctuations will affect the Group’s financial position. Based on analysis of the circumstances, management assesses the benefits of forward hedging monthly sales contracts for the purpose of protecting cash flow. If management believes that a hedging contract will appropriately help manage cash flow then it may choose to enter into a commodity price hedge. The Group does not currently have any covenants under its current financing facilities to hedge future production. The Group had oil price sale financial hedges outstanding as at September 30, 2026, which are summarized as follows: Period Volume (barrels per day) Type Average Pricing October 1, 2026 - December 31, 2026 5,000 WTI/WCS Differential USD -12.50/bbl October 1, 2026 - December 31, 2027 5,000 WCS (Hardisty to Houston)1 USD -7.55/bbl January 1, 2027 - December 31, 2027 5,000 WCS (Hardisty to Houston)1 USD -7.50/bbl October 1, 2026 - December 31, 2026 2,000 ARV2 USD -3.65/bbl 1 Represents the cost of transporting a barrel of WCS quality from Hardisty, Alberta to Houston, Texas. 2 Represents the difference in USD of a barrel of WCS quality in Houston against a barrel of WTI quality. The Group had gas price sale financial hedges outstanding as at September 30, 2026, which are summarized as follows: Period Volume (Gigajoules (GJ) per day) Type Average Pricing October 1, 2026 - October 31, 2026 15,000 AECO Swap CAD 2.73/GJ The Group had electricity financial hedges outstanding as at September 30, 2026, which are summarized as follows: Period Volume (MWh) Type Average Pricing October 1, 2026 - September 30, 2040 3 AESO CAD 75.00/MWh The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had a positive fair value of USD 8,053 thousand as at September 30, 2026. 22
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 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. The Group entered into currency hedges to: (i) sell a total USD 120 million for the period January 2027 to December 2027 at an average rate of CAD 1.3842 (buy CAD); (ii) purchase a total EUR 15.6 million for the period January 2027 to October 2027 at an average rate of EUR 1.1432 (sell USD); (iii) purchase a total MYR 72 million for the period January 2027 to October 2027 at an average rate of MYR 4.0331 (sell USD). The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had a negative fair value of USD 1,290 thousand as at September 30, 2026. 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. There are currently no interest rate hedges. Credit Risk The Group may be exposed to third party credit risk through contractual arrangements with counterparties who buy the Group’s hydrocarbon products. The Group’s policy is to limit credit risk by only entering into oil and gas sales agreements with reputable and creditworthy oil and gas and trading companies. Where it is determined that there is a credit risk for oil and gas sales, the Group’s policy is to require credit enhancement from the purchaser. The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In addition, cash is to be held and transacted only through major banks. RISK FACTORS IPC is engaged in the exploration, development and production of oil and gas and its operations are subject to various risks and uncertainties which include, but are not limited to, those listed below. For further information and discussion of these risks and uncertainties, please see IPC’s Annual Information Form for the year ended December 31, 2025 (”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 Resources Advisory” below. 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 Group’s internal control over financial reporting during the three and nine months ended September 30, 2026, 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). Management concluded that the Corporation’s internal control over financial reporting was effective as of September 30, 2026. 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. 23
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 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: • 2026 production ranges (including total daily average production), production composition, cash flows, operating costs 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 navigate the Corporation through periods of volatile commodity prices; • The ability to fully fund IPC’s future expenditures from cash flows and current borrowing capacity; • IPC’s intention and ability to continue to implement its strategies to build long-term shareholder value; • The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth; • The continued facility uptime and reservoir performance in IPC’s areas of operation; • Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing, regulatory approvals, third party commercial arrangements, breakeven oil prices, net present values and future phase developments; • Current and future production performance, operations and development potential of the Onion Lake Thermal, Suffield, Brooks and Ferguson operations, including the timing and success of future oil and gas drilling and optimization programs; • The potential improvement in the Canadian oil egress situation and IPC’s ability to benefit from any such improvements; • The ability of IPC to maintain current and forecast production in France and Malaysia; • The ability of IPC to renew the NCIB and the number of common shares which may be purchased under a renewed NCIB; • The intention and ability of IPC to acquire common shares under the NCIB, including the timing of any such purchases; • The return of value to IPC’s shareholders as a result of the NCIB; • IPC’s ability to implement its greenhouse gas (GHG) emissions intensity and climate strategies and to achieve its net GHG emissions intensity reduction targets; • IPC’s ability to implement projects to reduce net GHG emissions intensity, including potential carbon capture and storage; • Estimates of reserves and contingent resources; • The ability to generate free cash flows and use that cash to repay debt; • IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the Corporation; • IPC’s ability to identify and complete future acquisitions; • Expectations regarding the oil and gas industry in Canada, Malaysia and France, including assumptions regarding future royalty rates, regulatory approvals, legislative changes, tariffs, and ongoing projects and their expected completion; and • Future drilling and other exploration and development activities. Statements relating to “reserves“ and “contingent resources“ are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management. See also “Reserves and Resources Advisory“. The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations and assumptions concerning: the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; 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; IPC’s ability to maintain its existing credit ratings; IPC’s ability to achieve its performance targets; 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 and that IPC will be able to implement its standards, controls, procedures and policies in respect of any acquisitions and realize the expected synergies on the anticipated timeline or at all; 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; IPC’s intention to complete share repurchases under the normal course issuer bid program, including the funding of such share repurchases, existing and future market conditions, including with respect to the price of IPC’s common shares, and compliance with respect to applicable limitations under securities laws and regulations and stock exchange policies; 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. 24
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 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; innovation and cybersecurity risks related to IPC’s systems, including costs of addressing or mitigating such risks; the ability to attract, engage and retain skilled employees; 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; geopolitical conflicts, including current and potential future conflicts in Ukraine, the Middle East, South America and elsewhere and their potential impact on, among other things, global market conditions; political or economic developments, including, without limitation, the risk that (i) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S. will trigger a broader global trade war which could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Corporation, including by decreasing demand for, and the price of oil, and natural gas, disrupting supply chains, increasing costs, causing volatility in the global financial markets, and limiting access to financing; 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 Factors”. Estimated production and FCF generation are based on IPC’s current business plans over the periods of 2026 to 2030 and 2031 to 2035, less net debt of USD 484 million as at December 31, 2025, with assumptions based on the reports of IPC’s independent reserves evaluator and auditor, and including certain corporate adjustments relating to estimated general and administrative costs and hedging, and excluding shareholder distributions and certain refinancing costs. Assumptions include average net production of approximately 62 Mboepd over the period of 2026 to 2030, average capital expenditures of approximately USD 5 per boe, average operating costs of approximately USD 18 to 20 per boe, average Brent oil prices of USD 65 to 95 per bbl escalating by 2% per year, and average Brent to Western Canadian Select differentials and average gas prices as estimated by IPC’s independent reserves evaluator and auditor 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, 2025 (see “Cautionary Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk Factors”) and other reports on file with applicable securities regulatory authorities, including previous financial reports, management’s discussion and analysis and material change reports, which may be accessed through the SEDAR+ website (www.sedarplus.ca) or IPC’s website (www. international-petroleum.com). Management of IPC approved the production, operating costs, operating cash flow, capital and decommissioning expenditures and free cash flow guidance and estimates contained herein as of the date of this MD&A. 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 and France/Malaysia are effective as of December 31, 2025, and are included in the reports prepared by Sproule International Limited and ERC Equipoise Ltd., respectively (collectively, Sproule ERCE), an independent qualified reserves evaluator and auditor, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule ERCE’s December 31, 2025 price forecasts. The price forecasts used in the Sproule ERCE reports, are available on the website of Sproule ERCE (sproule-erce.com) and are contained in the AIF . These price forecasts are as at December 31, 2025 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 521 MMboe as at December 31, 2025, by the mid-point of the 2026 CMD production guidance of 44,000 to 47,000 boepd. The product types comprising the 2P reserves and contingent resources described in this MD&A are contained in the AIF . See also “Supplemental Information regarding Product Types” below. Light, medium and heavy crude oil and bitumen reserves/ resources disclosed in this MD&A include solution gas and other by-products. 25
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 “2P reserves“ means proved plus probable reserves. “Proved reserves“ are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. “Probable reserves“ are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Each of the reserves categories reported (proved and probable) may be divided into developed and undeveloped categories. “Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. “Developed producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. “Developed non-producing reserves” are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. “Undeveloped reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or characterized by their economic status. There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent 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 contingencies can be clearly defined. Chance of development is the probability of a project being commercially viable. Where risked resources are presented, they have been adjusted based on the chance of development by multiplying the unrisked values by the chance of development. 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 for contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies required for the re-classification of the contingent resources as reserves being resolved. Therefore, unrisked reported volumes of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such resources. The contingent resources reported in this MD&A are estimates only. The estimates are based upon a number of factors and assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this MD&A. References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”. 2P reserves and contingent resources included in the reports prepared by Sproule ERCE have been aggregated. 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 reserves and resources evaluations will be attained and variances could be material. 26
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel (bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value. Supplemental Information regarding Product Types The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily production figures provided in this document: Heavy Crude Oil (Mbopd) Light and Medium Crude Oil (Mbopd) Conventional Natural Gas (per day) Total (Mboepd) Three months ended September 30, 2026 24.7 5.5 83.1 MMcf (13.8 Mboe) 44.0 September 30, 2025 24.5 6.5 89.3 MMcf (14.9 Mboe) 45.9 Nine months ended September 30, 2026 23.2 5.8 84.6 MMcf (14.1 Mboe) 43.1 September 30, 2025 23.5 6.3 89.1 MMcf (14.8 Mboe) 44.6 Year ended December 31, 2025 December 31, 2025 23.6 6.4 89.6MMcf (14.9 Mboe) 44.9 This MD&A also makes reference to IPC’s forecast total average daily production of 44,000 to 47,000 boepd for 2026. IPC estimates that approximately 57% of that production will be comprised of heavy crude oil, approximately 12% will be comprised of light and medium crude oil and approximately 31% will be comprised of conventional natural gas. 27
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 OTHER SUPPLEMENTARY INFORMATION Currency Abbreviations CAD Canadian dollar MCAD Million Canadian dollar EUR Euro MEUR Million Euro USD US dollar MUSD Million US dollar MYR Malaysian Ringgit MMYR Million Malaysian Ringgit 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 ARV Argus WCS Houston (represents the differential, in USD, between a barrel of WCS quality in Houston and WTI) ASP Alkaline surfactant polymer (an EOR process) bbl Barrel (1 barrel = 159 litres) boe Barrels of oil equivalents boepd Barrels of oil equivalents per day bopd Barrels of oil per day Bcf Billion 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 FPSO Floating Production Storage and Offloading (facility) 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 Megawatt MWh Megawatt-hour NGL Natural gas liquid SAGD Steam assisted gravity drainage WTI West Texas Intermediate WCS Western Canadian Select 28
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Management’s Discussion and Analysis For the three and nine months ended September 30, 2026 DIRECTORS C. Ashley Heppenstall Director, Chair London, England William Lundin Director, President and Chief Executive Officer Coppet, Switzerland Chris Bruijnzeels Director Abcoude, The Netherlands Donald K. Charter Director Toronto, Ontario, Canada Lukas (Harry) H. Lundin Director Toronto, Ontario, Canada Emily Moore Director Toronto, Ontario, Canada Mike Nicholson Director Monaco Deborah Starkman Director Toronto, Ontario, Canada OFFICERS William Lundin President and Chief Executive Officer Coppet, Switzerland Christophe Nerguararian Chief Financial Officer Geneva, Switzerland Nicki Duncan Chief Operating Officer Geneva, Switzerland Jeffrey Fountain General Counsel and Corporate Secretary Geneva, Switzerland Rebecca Gordon Senior Vice President Corporate Planning and Investor Relations Geneva, Switzerland Chris Hogue Senior Vice President Canada Calgary, Alberta, Canada Ryan Adair Vice President Asset Management and Corporate Planning Canada Calgary, Alberta, Canada Curtis White Vice President Commercial Canada Calgary, Alberta, Canada MEDIA AND INVESTOR RELATIONS Robert Eriksson Stockholm, Sweden CORPORATE OFFICE Suite 2800, 1055 Dunsmuir Street Vancouver, British Columbia V7X 1L2 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 LLP , Canada TRANSFER AGENT Computershare Trust Company of Canada Calgary, Alberta, and Toronto, Ontario STOCK EXCHANGE LISTINGS Toronto Stock Exchange and NASDAQ Stockholm Trading Symbol: IPCO 29
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International Petroleum Corporation Suite 2800 1055 Dunsmuir Street Vancouver, British Columbia V7X 1L2, Canada Tel: +1 604 689 7842 E-mail: info@international-petroleum.com Web: international-petroleum.com□