Kvartalsrapport Q3 2024

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===== SIDA 1 =====

Q3
International Petroleum Corporation
Interim Condensed Consolidated 
Financial Statements
For the three and nine months ended September 30, 2024

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2
Contents
Interim Condensed Consolidated Statement of Operations  3
Interim Condensed Consolidated Statement of Comprehensive Income  4
Interim Condensed Consolidated Balance Sheet  5
Interim Condensed Consolidated Statement of Cash Flow 6
Interim Condensed Consolidated Statement of Changes in Equity 7
Notes to the Interim Condensed Consolidated Financial Statements 8
Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

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3
Interim Condensed Consolidated Statement of Operations
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED
Three months ended
September 30
Nine months ended
September 30
USD Thousands Note 2024 2023 2024 2023
Revenue 2 173,200 257,366 598,659 655,446 
Cost of sales
Production costs 3 (100,984) (130,765) (328,110) (364,889)
Depletion and decommissioning costs 2,8 (30,491) (31,687) (96,305) (71,488)
Depreciation of other tangible fixed assets 2,8 (2,023) (1,509) (6,503) (6,503)
Exploration and business development costs 2 (197) 24 (344) (2,007)
Gross profit 2 39,505 93,429 167,397 210,559
Sale of assets 8 – 11,912 – 11,912
General, administration and depreciation expenses (4,249) (3,952) (12,178) (12,304)
Profit before financial items 35,256 101,389 155,219 210,167
Finance income 4 9,472 5,833 16,389 14,238
Finance costs 5 (13,596) (10,090) (40,331) (30,465)
Net financial items (4,124) (4,257) (23,942) (16,227)
Profit before tax 31,132 97,132 131,277 193,940
Income tax expense 6 (8,257) (25,451) (29,473) (50,671)
Net result 22,875 71,681 101,804 143,269
Net result attributable to:
Shareholders of the Parent Company 22,874 71,673 101,788 143,247
Non-controlling interest 1 8 16 22
22,875 71,681 101,804 143,269
Earnings per share – USD1 14 0.19 0.56 0.81 1.08
Earnings per share fully diluted – USD1 14 0.18 0.54 0.80 1.05
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
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED
Three months ended
September 30
Nine months ended
September 30
USD Thousands Note 2024 2023 2024 2023
Net result 22,875 71,681 101,804 143,269
Other comprehensive income
Items that may be reclassified to profit or loss:
Gain/(loss) on cash flow hedges 23,464 (2,274) (11,302) 6,339
Reclassification of hedging (gains)/losses to profit or 
loss 2 (5,366) (1,854) (11,928) (11,969)
Income tax relating to these items (4,294) 1,044 5,639 1,389
Currency translation adjustments 14,772 (11,811) (16,439) 5,100
Total comprehensive income 51,451 56,786 67,774 144,128
Total comprehensive income attributable to:
Shareholders of the Parent Company 51,437 56,781 67,760 144,114
Non-controlling interest 14 5 14 14
51,451 56,786 67,774 144,128
See accompanying notes to the interim condensed consolidated financial statements

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5
Interim Condensed Consolidated Balance Sheet
As at September 30, 2024 and December 31, 2023, UNAUDITED
USD Thousands Note September 30, 2024 December 31, 2023
ASSETS
Non-current assets
Exploration and evaluation assets 7 1,434 –
Property, Plant and Equipment 8 1,491,700 1,303,860
Right-of-use assets 3,244 2,814
Deferred tax assets 6 1,281 1,827
Derivative instruments 18 831 7,049
Other assets 9 52,445 56,838
Total non-current assets 1,550,935 1,372,388
Current assets
Inventories 10 24,369 21,808
Trade and other receivables 11 112,219 113,497
Derivative instruments 18 19,639 35,504
Current tax receivables 823 2,714
Cash and cash equivalents 12 299,203 517,074
Total current assets 456,253 690,597
TOTAL ASSETS 2,007,188 2,062,985
LIABILITIES
Non-current liabilities
Financial liabilities 15, 18 2,772 5,442
Bonds 15, 18 438,648 435,041
Lease liabilities 2,915 2,087
Provisions 16 257,536 250,657
Deferred tax liabilities 6 103,595 86,348
Derivative instruments 18 1,398 263
Total non-current liabilities 806,864 779,838
Current liabilities
Trade and other payables 17 139,564 188,871
Financial liabilities 15, 18 3,659 3,589
Derivative instruments 18 2,000 1,267
Current tax liabilities 2,188 255
Lease liabilities 587 809
Provisions 16 8,320 8,097
Total current liabilities 156,318 202,888
EQUITY
Shareholders’ equity 1,043,848 1,080,074
Non-controlling interest 158 185
Net shareholders’ equity 1,044,006 1,080,259
TOTAL EQUITY AND LIABILITIES 2,007,188 2,062,985
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, 2024 and 2023, UNAUDITED
Three months ended
September 30
Nine months ended
September 30
USD Thousands Note 2024 2023 2024 2023
Cash flow from operating activities
Net result 22,875 71,681 101,804 143,269
Adjustments for non-cash related items:
Depletion, depreciation and amortization 2,8 32,860 33,601 103,741 79,180
Gain on sale of assets 8 – (11,912) – (11,912)
Income tax 6 8,257 25,451 29,473 50,671
Amortization of capitalized financing fees 5 524 339 1,534 1,120
Foreign currency exchange loss/(gain) 4,5 (5,360) (854) (1,743) 1,493 
Interest income 4 (4,112) (4,979) (14,646) (14,238)
Interest expense 5 9,119 5,787 26,865 16,591 
Unwinding of asset retirement obligation discount 5 3,680 3,479 10,939 10,021 
Share-based costs 2,267 1,907 6,443 6,847 
Other 241 214 557 629 
Cash flow generated from operations (before 
working capital adjustments and income taxes) 70,351 124,714 264,967 283,671
Changes in working capital  14,213 (3,527) (56,814) (10,171)
Decommissioning costs paid 16 (2,575) (2,755) (4,938) (7,126)
Other payments 16 – – (504) (864)
Net income taxes refunded/(paid) (3,206) (7,043) (2,929) (33,117)
Interest received 3,669 5,948 11,948 13,713 
Interest paid (16,358) (10,985) (32,772) (21,946)
Net cash flow from operating activities 66,094 106,352 178,958 224,160 
Cash flow used in investing activities
Investment in property, plant and equipment 7,8 (99,218) (76,909) (308,704) (184,386)
Disposal of assets 8 – 13,736 – 13,736
Acquisitions net of cash acquired – – – (59,419)
Net cash (outflow) from investing activities (99,218) (63,173) (308,704) (230,069)
Cash flow from financing activities
Repayments 15 (586) (894) (2,600) (2,630)
Net Bonds issuance proceeds 15 – 137,550 – 137,550
Paid financing fees – – – (507)
Repurchase of own shares (“NCIB”) 13 (35,205) (12,138) (80,943) (72,293)
Other payments (217) (283) (689) (728)
Net cash (outflow) from financing activities (36,008) 124,235 (84,232) 61,392
Change in cash and cash equivalents (69,132) 167,414 (213,978) 55,483
Cash and cash equivalents at the beginning of the 
period 368,797 374,177 517,074 487,240
Currency exchange difference in cash and cash 
equivalents (462) 1,017 (3,893) (115) 
Cash and cash equivalents at the end of the period 299,203 542,608 299,203 542,608
   
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, 2024 and 2023, 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, 2024 230,005 808,846 (10,745) 18,838 31,344 1,786 1,080,074 185 1,080,259
Net result – 101,788 – – – – 101,788 16 101,804
Cash flow hedges – – – – (17,591) – (17,591) – (17,591)
Currency translation difference – – (13,659) (2,057) (721) – (16,437) (2) (16,439)
Total comprehensive income – 101,788 (13,659) (2,057) (18,312) – 67,760 14 67,774
Repurchase of own shares 
(NCIB)1 (82,558) – – – – – (82,558) – (82,558)
Dividend distribution – – – – – – – (41) (41)
Share based costs – – – 6,443 – – 6,443 – 6,443
Share based payments2 (21,740) – – (6,131) – – (27,871) – (27,871)
Balance at September 30, 2024 125,707 910,634 (24,404) 17,093 13,032 1,786 1,043,848 158 1,044,006
1  See Note 13
2 The third instalment of IPC RSP 2021 awards, the second instalment of IPC RSP 2022 awards, the first instalment of IPC RSP 2023 awards and 
the IPC PSP 2021 awards vested on January 31, 2024, at a price of CAD 14.90 per award. The difference between the value at vesting date 
and at grant (respectively CAD 4.07 per award, CAD 9.09 per award, CAD 14.27 per award and CAD 3.61 per award) was offset against 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, 2023 338,719 635,895 (31,292) 11,349 7,958 2,511 965,140 191 965,331
Net result – 143,247 – – – – 143,247 22 143,269
Acquisitions – – – – 881 – 881 – 881
Cash flow hedges – – – – (5,122) – (5,122) – (5,122) 
Currency translation difference – – 5,251 (189) 46 – 5,108 (8) 5,100
Total comprehensive income – 143,247 5,251 (189) (4,195) – 144,114 14 144,128
Dividend distribution – – – – – – – (31) (31)
Repurchase of own shares 
(NCIB)1 (72,293) – – – – – (72,293) – (72,293)
Share based costs – – – 19,805 – – 19,805 – 19,805
Share based payments2                     (13,415) – – (18,399) – – (31,814) – (31,814)
Balance at September 30, 2023 253,011 779,142 (26,041) 12,566 3,763 2,511 1,024,952 174 1,025,126
1  See Note 13
2 The third instalment of IPC RSP 2020 awards, the second instalment of IPC RSP 2021 awards, the first instalment of IPC RSP 2022 awards and 
the IPC PSP 2020 awards vested on January 31, 2023, at a price of CAD 14.26 per award. The difference between the value at vesting date 
and at grant (respectively CAD 4.35 per award, CAD 4.07 per award, CAD 9.09 per award and CAD 3.65 per award) was offset against share 
premium. 
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, 2024 and 2023, UNAUDITED
1. CORPORATE INFORMATION
A. The Group
International Petroleum Corporation (“IPC” or the “Corporation” and, together with its subsidiaries, the “Group”) is in the business 
of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development 
projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange (“TSX”) in Canada and the Nasdaq Stockholm 
Exchange in Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada under the Business Corporations 
Act. The address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business 
address is Suite 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 International 
Accounting Standard 34, Interim Financial Reporting (“IAS 34”) using accounting policies consistent with IFRS Accounting 
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The unaudited interim consolidated 
financial statements should be read in conjunction with IPC’s annual consolidated financial statements for the year ended 
December 31, 2023, which have been prepared in accordance with IFRS as issued by the IASB.
These unaudited interim consolidated financial statements are presented in United States Dollars (USD), which is the Group’s 
presentation and functional currency. The unaudited interim consolidated financial statements have been prepared on a historical 
cost basis, except for items that are required to be accounted for at fair value as detailed in the Group’s accounting policies. 
Intercompany transactions and balances have been eliminated. Certain comparative figures have been reclassified to conform with 
the financial statements presentation in the current year
The unaudited interim condensed consolidated financial statements have been approved by the Board of Directors of IPC and
authorized for issuance on November 5, 2024.
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, 2023.
C. Change in presentation
The following items within the interim condensed consolidated balance sheet were reclassified to conform to the current year’s 
presentation:
• Oil and gas properties and other tangible fixed assets, formerly presented separately as “Oil and gas properties” and “Other 
tangible fixed assets”, are now presented together on the interim condensed consolidated balance sheet as “Property, Plant 
and Equipment”. Refer to Note 8.
D. Going concern
The Group’s interim condensed consolidated financial statements for the nine months period ended September 30, 2024, have 
been prepared on a going concern basis, which assumes that the Group will be able to realize its assets and discharge its liabilities 
in the normal course of business as they become due in the foreseeable future.
E. Changes in accounting policies and disclosures
During the nine months ended September 30, 2024, the Group has applied the accounting standards, interpretations and annual
improvement points that are effective as of January 1, 2024.
F. Future accouting changes 
On April 9, 2024, the IASB issued IFRS 18 Presentation and Disclosure in Financial Statements (”IFRS 18”), which aims to improve 
how companies communicate their financial statements, with a focus on information about financial performance in the statement 
of profit or loss. IFRS 18 is effective January 1, 2027. The Company is in the process of assessing the impact that the standard will 
have on its financial statements.

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9
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, 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 7 and 8.
Three months ended September 30, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 157,123 17,876 15,939 – 190,938
NGLs 243 – – – 243
Gas 3,889 – – – 3,889
Net sales of oil and gas 161,255 17,876 15,939 – 195,070
Change in under/over lift position – – 1,289 – 1,289
Royalties (27,604) – (1,164) – (28,768)
Hedging settlement 5,366 – – – 5,366
Other operating revenue – – 216 27 243
Revenue 139,017 17,876 16,280 27 173,200
Operating costs (56,958) (9,140) (7,823) – (73,921)
Cost of blending (29,818) – – – (29,818)
Change in inventory position (330) 3,516 (431) – 2,755
Depletion and decommissioning costs (21,092) (6,285) (3,114) – (30,491)
Depreciation of other tangible fixed assets – (2,023) – – (2,023)
Exploration and business development costs – – – (197) (197)
Gross profit/(loss) 30,819 3,944 4,912 (170) 39,505
Three months ended September 30, 2023
USD Thousands Canada Malaysia France Other Total
Crude oil 201,513 46,148 19,318 – 266,979
NGLs 377 – – – 377
Gas 16,705 – – – 16,705
Net sales of oil and gas 218,595 46,148 19,318 – 284,061
Change in under/over lift position – – 4,349 – 4,349
Royalties (31,973) – (1,239) – (33,212)
Hedging settlement 1,854 – – – 1,854
Other operating revenue – – 229 85 314
Revenue 188,476 46,148 22,657 85 257,366
Operating costs (62,796) (11,062) (9,004) – (82,862)
Cost of blending (39,836) – – – (39,836)
Change in inventory position 315 (8,478) 96 – (8,067)
Depletion and decommissioning costs (24,593) (3,438) (3,656) – (31,687)
Depreciation of other tangible fixed assets – (1,509) – – (1,509)
Exploration and business development costs – – – 24 24
Gross profit/(loss) 61,566 21,661 10,093 109 93,429

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10
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED
Nine months ended September 30, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 517,757 75,770 49,909 – 643,436
NGLs 762 – – – 762
Gas 24,981 – – – 24,981
Net sales of oil and gas 543,500 75,770 49,909 – 669,179
Change in under/over lift position – – 6,420 – 6,420
Royalties (86,376) – (3,464) – (89,840)
Hedging settlement 11,928 – – – 11,928
Other operating revenue – – 670 302 972
Revenue 469,052 75,770 53,535 302 598,659
Operating costs (166,648) (23,385) (24,538) – (214,571)
Cost of blending (116,699) – – – (116,699)
Change in inventory position (287) 3,726 (279) – 3,160
Depletion and decommissioning costs (66,482) (20,208) (9,615) – (96,305)
Depreciation of other tangible fixed assets – (6,503) – – (6,503)
Exploration and business development costs – – – (344) (344)
Gross profit/(loss) 118,936 29,400 19,103 (42) 167,397
Nine months ended September 30, 2023
USD Thousands Canada Malaysia France Other Total
Crude oil 521,383 85,924 52,476 – 659,783
NGLs 845 – – – 845
Gas 52,564 – – – 52,564
Net sales of oil and gas 574,792 85,924 52,476 – 713,192
Change in under/over lift position – – 8,842 – 8,842
Royalties (75,713) – (3,575) – (79,288)
Hedging settlement 11,969 – – – 11,969
Other operating revenue 7 – 639 85 731
Revenue 511,055 85,924 58,382 85 655,446
Operating costs (187,476) (26,509) (24,609) – (238,594)
Cost of blending (128,523) – – – (128,523)
Change in inventory position 269 2,141 (182) – 2,228
Depletion and decommissioning costs1 (46,285) (14,818) (10,385) – (71,488)
Depreciation of other tangible fixed assets – (6,503) – – (6,503)
Exploration and business development costs (834) – (9) (1,164) (2,007)
Gross profit/(loss) 148,206 40,235 23,197 (1,079) 210,559
1  In Canada, includes an adjustment in the first quarter of 2023 for accelerated decommissioning activities funded by a non-cash site rehabilitation 
program.

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11
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED
3. PRODUCTION COSTS
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2024 2023 2024 2023
Cost of operations 64,027 70,887 183,223 205,039
Tariff and transportation expenses 8,676 10,643 27,606 29,701
Direct production taxes 1,218 1,332 3,742 3,854
Operating costs 73,921 82,862 214,571 238,594
Cost of blending1 29,818 39,836 116,699 128,523
Change in inventory position (2,755) 8,067 (3,160) (2,228)
Total production costs 100,984 130,765 328,110 364,889
1  In Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. Cost of blending represents the contracted 
purchase of diluent used for blending.
4. FINANCE INCOME
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2024 2023 2024 2023
Foreign exchange gain, net 5,360 854 1,743 – 
Interest income 4,112 4,979 14,646 14,238
Total finance income 9,472 5,833 16,389 14,238
5. FINANCE COSTS
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2024 2023 2024 2023
Foreign exchange loss, net – – – 1,493
Interest expense 9,119 5,787 26,865 16,591
Unwinding of asset retirement obligation discount 3,680 3,479 10,939 10,021
Amortization of capitalized financing fees 524 339 1,534 1,120
Loan commitment fees 169 189 614 463
Other financial costs 104 296 379 777
Total finance costs 13,596 10,090 40,331 30,465
6. INCOME TAX
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2024 2023 2024 2023
Current tax 373 (7,459) (6,718) (16,045)
Deferred tax (8,630) (17,992) (22,755) (34,626)
Total tax expense (8,257) (25,451) (29,473) (50,671)
The Group is within the scope of the OECD Pillar Two model rules. Pillar Two legislation is enacted or expected to be enacted in all 
relevant Group entities in 2024, and with effect from January 1, 2024. The Group applies the exception to recognising and disclosing 
information about deferred tax assets and liabilities related to Pillar Two income taxes, as provided in the amendments to IAS 12 
issued in May 2023. All relevant entities within the Group have an effective tax rate that exceeds 15% and as such the impact is 
insignificant.

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12
Specification of deferred tax assets and tax liabilities1
USD Thousands September 30, 2024 December 31, 2023
Unused tax loss carry forward 29,325 34,446
Other 5,727 5,959
Deferred tax assets 35,052 40,405
Accelerated allowances 133,478 115,399
Derivative hedges 3,888 9,527
Deferred tax liabilities 137,366 124,926
Deferred taxes, net (102,314) (84,521)
1  The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the 
balance sheet when they relate to the same jurisdiction.
The deferred tax liabilities consist of accelerated allowances, being the difference between the book and the tax value of oil and 
gas properties and site restoration provisions. The deferred tax liabilities will be released over the life of the oil and gas assets as 
the book value is depleted for accounting purposes. 
Deferred tax assets in relation to tax loss carried forwards are only recognized in so far that there is a reasonable certainty as to
the timing and the extent of their realization. The recognized unused tax loss carry forward mainly relates to Canada. The Group
has concluded that the deferred assets will be recoverable using the estimated future taxable income based on the approved
business plans and budgets.
7. EXPLORATION AND EVALUATION ASSETS
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 – – – –
Additions 352 1,082 – 1,434
Net book value September 30, 2024 352 1,082 – 1,434
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 – – 4,764 4,764
Additions – – 39 39
Write-off – – (39) (39)
Reclassification – – (4,937) (4,937)
Currency translation adjustments – – 173 173
Net book value December 31, 2023 – – – –
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

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13
8. PROPERTY, PLANT AND EQUIPMENT
USD Thousands 2024 2023
Oil and gas properties 1,472,762 1,278,422
Other tangible fixed assets 18,938 25,438
Property, Plant and Equipment 1,491,700 1,303,860
Oil and gas properties
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 1,465,010 591,123 436,693 2,492,826
Additions 287,960 16,372 2,691 307,023
Change in estimates 1,755 – – 1,755
Currency translation adjustments (26,973) – 5,801 (21,172)
September 30, 2024 1,727,752 607,495 445,185 2,780,432
Accumulated depletion
January 1, 2024 (398,288) (502,834) (313,282) (1,214,404)
Depletion charge for the period (66,482) (20,208) (9,615) (96,305)
Currency translation adjustments 7,412 – (4,373) 3,039
September 30, 2024 (457,358) (523,042) (327,270) (1,307,670)
Net book value September 30, 2024 1,270,394 84,453 117,915 1,472,762
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 1,089,789 566,606 399,237 2,055,632
Acquisitions 72,242 – – 72,242
Additions 278,613 17,873 16,204 312,690
Disposals1 (7,854) – – (7,854)
Change in estimates 24,454 6,644 1,738 32,836
Reclassification (22,857) – 4,937 (17,920)
Currency translation adjustments 30,623 – 14,577 45,200
December 31, 2023 1,465,010 591,123 436,693 2,492,826
Accumulated depletion
January 1, 2023 (323,273) (485,034) (288,714) (1,097,021)
Depletion charge for the period (94,192) (17,800) (14,018) (126,010)
Disposals1 4,474 – – 4,474
Other2 22,857 – – 22,857
Currency translation adjustments (8,154) – (10,550) (18,704)
December 31, 2023 (398,288) (502,834) (313,282) (1,214,404)
Net book value December 31, 2023 1,066,722 88,289 123,411 1,278,422
1  In Canada, includes the disposal of non-core properties in the John Lake area.
2  In Canada, includes an adjustment in the first quarter of 2023 for accelerated decommissioning activities funded by a non-cash site rehabilitation 
program. 
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

===== SIDA 14 =====

14
Other tangible fixed assets
USD Thousands FPSO Other Total
Cost
January 1, 2024 204,853 10,048 214,901
Additions – 247 247
September 30, 2024 204,853 10,295 215,148
Accumulated depreciation
January 1, 2024 (181,123) (8,340) (189,463)
Depreciation charge for the period1 (6,503) (242) (6,745)
Currency translation adjustments – (2) (2)
September 30, 2024 (187,626) (8,584) (196,210)
Net book value September 30, 2024 17,227 1,711 18,938
USD Thousands FPSO Other Total
Cost
January 1, 2023 204,853 9,779 214,632
Additions – 510 510
Disposals – (487) (487)
Currency translation adjustments – 246 246
December 31, 2023 204,853 10,048 214,901
Accumulated depreciation
January 1, 2023 (173,311) (7,947) (181,258)
Depreciation charge for the period1 (7,812) (684) (8,496)
Disposals – 487 487
Currency translation adjustments – (196) (196)
December 31, 2023 (181,123) (8,340) (189,463)
Net book value December 31, 2023 23,730 1,708 25,438
1  Depreciation of Other is included in General, administration and depreciation expenses in the statement of operations.
The Floating Production Storage and Offloading facility (“FPSO“) located on the Bertam field, Malaysia, is being depreciated to its 
residual value on a unit of production basis to August 2025. The depreciation charge is included in the depreciation of other assets 
line in the statement of operations.
For office equipment and other assets, the depreciation charge for the year is based on cost and an estimated useful life of 3 to 
5 years. The depreciation charge is included within the general, administration and depreciation expenses in the Statement of 
Operations.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

===== SIDA 15 =====

15
9. OTHER NON-CURRENT ASSETS
USD Thousands September 30, 2024 December 31, 2023
Financial assets  37,383     41,332    
Intangible assets  15,062     15,506    
 52,445     56,838    
Financial assets mainly represent cash payments made to an asset retirement obligation fund for the Bertam field, Malaysia 
for an amount of USD 33.2 million (2023: USD 28.7 million). Financial assets also include cash-collaterized guarantees placed in 
2023 in respect of work commitments in Malaysia amounting to USD 4.0 million. 
Intangible assets mainly represent carbon offsets purchased in Canada. 
10. INVENTORIES
USD Thousands September 30, 2024 December 31, 2023
Hydrocarbon stocks  16,281    13,530    
Well supplies and operational spares  8,088    8,278
24,369 21,808
11. TRADE AND OTHER RECEIVABLES
USD Thousands September 30, 2024 December 31, 2023
Trade receivables  74,812     97,264
Underlift  7,655    1,029
Joint operations debtors  1,552    910
Prepaid expenses and accrued income  18,275    10,986
Other  9,925    3,308
112,219 113,497
Other receivables include secured amounts of USD 7.7 million towards the future asset retirement obligation for the Bertam 
field.
12. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include only cash at hand or held in bank accounts. 
13. SHARE CAPITAL
The Corporation’s issued common share capital is as follows:
Number of shares
Balance at January 1, 2023 136,827,999
Cancellation of repurchased common shares (NCIB) (9,835,933)
Balance at December 31, 2023 126,992,066
Cancellation of repurchased common shares (NCIB) (6,241,028)
Balance at September 30, 2024 120,751,038
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. 
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

===== SIDA 16 =====

16
As at January 1, 2023, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in
treasury.
During 2023, under the normal course issuer bid/share repurchase program announced in December 2022 and renewed in
December 2023 (NCIB), IPC purchased and cancelled an aggregate of 9,835,933 common shares.
As at December 31, 2023, IPC had a total of 126,992,066 common shares issued and outstanding, with no common shares
held in treasury.
During the first nine months of 2024, IPC purchased a total of 6,271,028 and cancelled 6,241,028 common shares under the NCIB. 
The average price of common shares purchased under the 2023/2024 NCIB was SEK 132/CAD 17 per share.
As at September 30, 2024, IPC had a total of 120,751,038 common shares issued and outstanding and held 30,000 common 
shares held in treasury.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange, do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares and do not impact the earnings per share calculations.
14. 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
2024 2023 2024 2023
Net result attributable to shareholders of the Parent Company, USD 22,874,360 71,672,906 101,788,043 143,247,365
Weighted average number of shares for the period  123,244,183 128,875,283  125,197,549 133,066,728
Earnings per share, USD  0.19 0.56  0.81 1.08
Weighted average diluted number of shares for the period  125,165,037 131,745,540  127,118,402 135,936,985
Earnings per share fully diluted, USD 0.18 0.54 0.80 1.05
15. FINANCIAL LIABILITIES
USD Thousands September 30, 2024 December 31, 2023
Current bank loans 3,659 3,589
Non current bank loans 2,772 5,442
Bonds 442,619 440,288
Capitalized financing fees (3,971) (5,247)
445,079 444,072
As at January 2023, IPC had USD 300 million of bonds outstanding, issued in February 2022 and maturing in February 2027 with a
fixed coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group also had a revolving
credit facility of CAD 75 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada. 
In Q3 2023, IPC completed a tap issue of USD 150 million under IPC’s existing 7.25% bond framework issued at 7% discount
to par value with proceeds amounting to USD 139.5 million before transaction costs. For accounting purposes, the discounted
amount was recognised in the balance sheet and the discount will be unwound over the period to maturity of the bond and
charged to the interest expense line of the Statement of Operations using the effective interest rate methodology. As at
September 30, 2024, IPC had a nominal USD 450 million of bonds outstanding with maturity in February 2027. The bond 
repayment obligations as at September 30, 2024, are classified as non-current as there are no mandatory repayments within the 
next twelve months.
During 2023, the Group increased the Canadian RCF from MCAD 75 to MCAD 180 with a maturity to May 2025. During Q2 
2024, the Group extended the maturity of the Canadian RCF to May 2026. The Canadian RCF is undrawn and fully available as 
at September 30, 2024. During Q3 2024, the Group entered into a letter of credit facility in Canada (the “LC Facility”) to cover 
existing operational letters of credit. As at September 30, 2024, operational letters of credit in an aggregate of MCAD 40.2 have 
been issued under the LC Facility, including letters of credit issued in Q2 2024 for a total amount of MCAD 35 to support the third 
party pipeline construction agreements for the Blackrod project during 2024 and 2025.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

===== SIDA 17 =====

17
As at September 30, 2024, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May
2026. IPC makes quarterly repayments of the French Facility and the amount remaining outstanding under the France Facility as 
at September 30, 2024 was USD 6 million (EUR 6 million). An amount of USD 3.5 million (EUR 3.2 million) drawn under the France 
Facility as at September 30, 2024 is classified as current representing the repayment planned within the next twelve months.
The Group is in compliance with the covenants of the bonds and its financing facilities as at September 30, 2024. 
Total net debt as at September 30, 2024 amounted to USD 157 million. Cash and cash equivalents held amounted to USD 299 
million as at September 30, 2024.
16. PROVISIONS
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2024 253,949 2,176 551 2,078 258,754
Additions – – – 389 389
Unwinding of asset retirement obligation discount 10,939 – – – 10,939
Payments (4,938) – – (504) (5,442)
Change in estimates 1,755 – – – 1,755
Reclassification1 1,013 – – – 1,013
Currency translation adjustments (1,814) 250 – 12 (1,552)
September 30, 2024 260,904 2,426 551 1,975 265,856
Non-current 253,796 1,214 551 1,975 257,536
Current 7,108 1,212 – – 8,320
Total 260,904 2,426 551 1,975 265,856
1 The reclassification of the asset retirement obligation related to the 2024 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 9). 
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2023 206,249 3,404 306 1,478 211,437
Acquisitions 29,885 – – – 29,885
Additions – – 446 938 1,384
Unwinding of asset retirement obligation discount 13,408 – – – 13,408
Disposals1 (2,483) – – – (2,483)
Changes in estimates 9,973 – 679 – 10,652
Payments (8,118) (1,081) (925) (364) (10,488)
Other2 (1,272) – – – (1,272)
Reclassification3 1,781 – – – 1,781
Currency translation adjustments 4,526 (147) 45 26 4,450
December 31, 2023 253,949 2,176 551 2,078 258,754
Non-current 246,396 1,632 551 2,078 250,657
Current 7,553 544 – – 8,097
Total 253,949 2,176 551 2,078 258,754
1 In Canada, includes the disposal of non-core properties in the John Lake area.
2 Includes accelerated decommissioning activities funded by a non cash site rehabilitation program.
3 The reclassification of the asset retirement obligation related to the 2023 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 9). 
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

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

18
The farm-in obligation relates to future payments for historic costs on the Bertam field in Malaysia payable for every 1 MMboe 
gross that the field produces above 10 MMboe gross and is capped at cumulative production of 27.5 MMboe gross. 
In calculating the present value of the asset retirement obligation provision, a blended rate of 6% (2023: 6%) per annum was used, 
based on a credit risk adjusted rate.
17. TRADE AND OTHER PAYABLES
USD Thousands September 30, 2024 December 31, 2023
Trade payables  18,153    42,761
Joint operations creditors  10,876    22,257
Accrued expenses  107,637    118,912
Other  2,898    4,941
139,564 188,871
18. 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, 2024
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 37,383 37,383 – –
Derivative instruments 20,470 – – 20,470
Joint operation debtors 1,552 1,552 – –
Other current receivables2 93,215 85,560 7,655 –
Cash and cash equivalents 299,203 299,203 – –
Financial assets 451,823 423,698 7,655 20,470
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
September 30, 2024
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 441,420 441,420 – –
Current financial liabilities 3,659 3,659 – –
Derivative instruments 3,398 – – 3,398
Joint operation creditors 10,876 10,876 – –
Other current liabilities 130,876 130,876 – –
Financial liabilities 590,229 586,831 – 3,398
December 31, 2023
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 41,332 41,332 – –
Derivative instruments 42,553 – – 42,553
Joint operation debtors 910 910 – –
Other current receivables2 104,315 103,286 1,029 –
Cash and cash equivalents 517,074 517,074 – –
Financial assets 706,184 662,602 1,029 42,553
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

===== SIDA 19 =====

19
December 31, 2023
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 440,483 440,483 – –
Current financial liabilities 3,589 3,589 – –
Derivative instruments 1,530 – – 1,530
Joint operation creditors 22,257 22,257 – –
Other current liabilities 166,869 166,869 – –
Financial liabilities 634,728 633,198 – 1,530
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
The carrying amount of the Group’s financial assets and liabilities approximate their fair values at the balance sheet dates.
 For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
  – Level 1: based on quoted prices in active markets;
  – Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
  – Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
September 30, 2024
USD Thousands Level 1 Level 2 Level 3
Other current receivables 7,655 – –
Derivative instruments – current – 19,639 –
Derivative instruments – non-current – 831 –
Financial assets 7,655 20,470 –
Derivative instruments – current – 2,000 336
Derivative instruments – non-current – – 1,062
Financial liabilities – 2,000 1,398
December 31, 2023
USD Thousands Level 1 Level 2 Level 3
Other current receivables 1,029 – –
Derivative instruments – current – 35,504 –
Derivative instruments – non-current – 7,049 –
Financial assets 1,029 42,553 –
Derivative instruments – current – 1,267 –
Derivative instruments – non-current – 61 202
Financial liabilities – 1,328 202
The Group had oil price sale financial hedges outstanding as at September 30, 2024 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
October 1, 2024 - December 31, 2024 17,700 WTI/WCS Differential USD -15.03/bbl
October 1, 2024 - December 31, 2024 12,250 WTI Sale Swap USD 80.26/bbl
October 1, 2024 - December 31, 2024 3,000 Brent Sale Swap USD 85.50/bbl
January 1, 2025 - December 31, 2025 8,000 WTI/WCS Differential USD -14.56/bbl
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

===== SIDA 20 =====

20
The Group had gas price sale financial hedges outstanding as at September 30, 2024 which are summarized as follows:
Period Volume (Gigajoules (GJ) per 
day)) Type Average Pricing 
October 1, 2024 - December 31, 2024 15,000 AECO Swap CAD 1.515/GJ
January 1, 2025 - December 31, 2025 10,000 AECO Swap CAD 2.500/GJ
The Group had electricity financial hedges outstanding as at September 30, 2024 which are summarized as follows:
Period Volume (MWh) Type Average Pricing 
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
In 2023, IPC entered into foreign currency hedges in Canada to buy CAD 20 million per month at CAD 1.36 (sell USD) and
in Malaysia to buy MYR 11.5 million per month at MYR 4.63 (sell USD) in respect of 2024, and to buy CAD 15 million per month at
CAD 1.36 (sell USD) in respect of 2025, to partially meet forecast operational expenses in those countries. In April 2024, IPC entered 
into currency hedge swaps from May 2024 to December 2024 to buy EUR 2.5 million per month, sell USD at an average exchange 
rate of 1.0705. In respect of the forecast Blackrod development capital expenditure in Canada, IPC entered into further currency 
hedges to purchase a total CAD 656 million for the period January 2024 to December 2025 at an average rate of CAD 1.33 (sell USD). 
The outstanding portion of all of the above hedges are treated as effective and changes to the fair value are reflected in other 
comprehensive income.
19. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In the normal course of business, the Group has committed to certain payments which are not recognised as liabilities. The 
following table summarizes the Group’s commitments in Canada as at September 30, 2024:
CAD Millions 2024 2025 2026 2027 2028 Thereafter
Transportation service1 7.0 33.3 60.6 89.2 92.8 1,488.2
Power2 3.1 12.4 12.4 12.4 9.8 –
Total commitments 10.1 45.7 73.0 101.6 102.6 1,488.2
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2045.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from October 1, 2024 to December 
31, 2028 and an additional 5MWh at a weighted average price of CAD 58.31/MWh from October 1, 2024 to December 31, 2027.
20. RELATED PARTIES
During the nine months ended September 30, 2024, the Group paid USD 333 thousand to the Lundin Foundation in respect of 
sustainability advisory services provided to the Group and USD 470 thousand to Orrön Energy AB in respect of office space rental. 
During the nine months ended September 30, 2024, Orrön Energy AB and ShaMaran Petroleum Corp. paid respectively USD 450 
thousand and USD 147 thousand to the Group in respect of support services provided during the first nine months of 2024.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with 
parties at arm’s length.
21. SUBSEQUENT EVENTS
In October 2024, the Group entered into the following oil price sale financial hedges in Canada:
Periodw Volume (barrels per day) Type Average Pricing 
January 1, 2025 - March 31, 2025 2,500 WTI Sale Swap USD 70.00/bbl
January 1, 2025 - December 31, 2025 3,000 WTI/WCS Differential USD -13.77/bbl
In October 2024, in respect of the forecast of operating expenditures in Canada, IPC entered into further currency hedges to purchase 
an additional CAD 90 million for the period January 2025 to December 2025 at an average rate of CAD 1.35 (sell USD). 
No other events have occurred since September 30, 2024, that are expected to have a substantial effect on this report.                         
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2024 and 2023, UNAUDITED

===== SIDA 21 =====

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

===== SIDA 22 =====

Q3
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three and nine months ended September 30, 2024

===== SIDA 23 =====

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Contents
Non-IFRS Measures
References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA), 
“operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under IFRS Accounting Standards (IFRS) and do not have any 
standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF , FCF , EBITDA, operating costs and net debt/net cash that may 
be used by other public companies. Management believes that OCF , FCF , EBITDA, operating costs and net debt/net cash are useful supplemental measures that may 
assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Non-IFRS measures should not be 
considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS measure is presented in this 
MD&A. See “Non-IFRS Measures” on page 19.
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 24.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada are effective as of December 
31, 2023, and are included in the reports prepared by Sproule Associates Limited (Sproule), an independent qualified reserves evaluator, in accordance with National 
Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using 
Sproule’s December 31, 2023, price forecasts. 
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in France and Malaysia are effective as of 
December 31, 2023, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), an independent qualified reserves auditor, in accordance with NI 51-101 and 
the COGE Handbook, and using Sproule’s December 31, 2023, price forecasts. 
Certain abbreviations and technical terms used in this MD&A are defined or described under the heading “Other Supplementary Information”.
INTRODUCTION  3
HIGHLIGHTS  4
OPERATIONS REVIEW  5
• Business Overview 5
• Operations Overview  7
FINANCIAL REVIEW  10
• Financial Results 10
• Capital Expenditure 18
• Financial Position and Liquidity  18
• Non-IFRS Measures 19
• Off-Balance Sheet Arrangements  21
• Outstanding Share Data  21
• Contractual Obligations and Commitments  21
• Critical Accounting Policies and Estimates 21
• Transactions with Related Parties  22
• Financial Risk Management  22
RISK FACTORS 23
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING  24
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION  24
RESERVES AND RESOURCES ADVISORY  26
OTHER SUPPLEMENTARY INFORMATION 28
2

===== SIDA 24 =====

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
INTRODUCTION
This management’s discussion and analysis (“MD&A”) for International Petroleum Corporation (“IPC” or the “Corporation” and, 
together with its subsidiaries, the “Group”) is dated November 5, 2024 and is intended to provide an overview of the Group’s 
operations, financial performance and current and future business opportunities. This MD&A should be read in conjunction with 
IPC’s unaudited interim condensed consolidated financial statement for the three and nine months ended September 30, 2024 as 
well as the audited consolidated financial statements and accompanying notes for the year ended December 31, 2023 (“Financial 
Statements”).
Group Overview
The Group is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production 
assets and development projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in 
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada, under the Business Corporations Act. The 
address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is 
Suite 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 International Accounting Standard 34, Interim 
Financial Reporting (“IAS 34”) using accounting policies consistent 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, 2024 September 30, 2023 December 31, 2023
Average Period end Average Period end Average Period end
1 EUR equals USD 1.0870 1.1196 1.0835 1.0594 1.0816 1.1050
1 USD equals CAD 1.3602 1.3516 1.3454 1.3429 1.3496 1.3251
1 USD equals MYR 4.6352 4.1235 4.5134 4.6952 4.5598 4.5950
              
IPC completed the acquisition of Cor4 Oil Corp. (“Cor4”) on March 3, 2023. In accordance with IFRS, the Financial Statements for 
periods in 2023 have been prepared on that basis, with revenues and expenses related to the Brooks assets acquired in the Cor4 
acquisition included in the Financial Statements from March 3, 2023. Certain 2023 operational and financial information included 
in the MD&A, including production, operating costs, OCF , FCF and EBITDA related to the Brooks assets acquired in the Cor4 
acquisition, are reported based on the effective date of the Cor4 acquisition of January 1, 2023. See also “Operations Overview – 
Production” and “Non-IFRS Measures” below.
3

===== SIDA 25 =====

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
HIGHLIGHTS
Q3 2024 Business Highlights
• Average net production of approximately 45,000 boepd for Q3 2024, in line with guidance (49% heavy crude oil, 17% light 
and medium crude oil and 34% natural gas).(1) 
• Successful completion of planned maintenance shutdowns at Onion Lake Thermal (OLT) in Canada and the Bertam field in 
Malaysia. 
• Drilling activity at the Suffield area in Canada continued with four wells drilled in Q3 2024 and completed by October 2024. 
• Development activities on Phase 1 of the Blackrod project continue to progress on schedule and on budget, with forecast first 
oil in late 2026. 
• 2.6 million IPC common shares purchased and cancelled during Q3 2024 under IPC’s normal course issuer bid (NCIB), on 
track to complete the 2023/2024 NCIB during November 2024.
• IPC plans to seek Toronto Stock Exchange approval for the renewal of the NCIB in December 2024.
 
Q3 2024 Financial Highlights
• Operating costs per boe of USD 17.9 for Q3 2024, below guidance .(3)
• Operating cash flow (OCF) and Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) of MUSD 73 and 
MUSD 68 respectively in line with guidance for Q3 2024 .(3)
• Capital and decommissioning expenditures of MUSD 102 for Q3 2024, in line with guidance.
• Free cash flow (FCF) for Q3 2024 amounted to MUSD -38 (MUSD 44 pre-Blackrod Phase 1 project funding) .(3)
• Gross cash of MUSD 299 and net debt of MUSD 157 as at September 30, 2024. (3)
• Net result of MUSD 23 for Q3 2024.
Reserves and Resources
• Total 2P reserves as at December 31, 2023 of 468 MMboe, with a reserves life index (RLI) of 27 years. (1)(2)
• Contingent resources (best estimate, unrisked) as at December 31, 2023 of 1,145 MMboe.(1)(2)
2024 Annual Guidance
• Full year 2024 average net production guidance range maintained at 46,000 to 48,000 boepd. (1)
• Full year 2024 operating costs guidance revised to below USD 18 per boe. (3)
• Full year 2024 OCF guidance estimated at between MUSD 335 and 342, assuming Brent USD 70 to 80 per barrel for the 
remainder of 2024.(3)
• Full year 2024 capital and decommissioning expenditures guidance forecast maintained at MUSD 437 .
• Full year 2024 FCF guidance estimated at between MUSD -140 and -133 (between MUSD 222 and 229 pre-Blackrod Phase 
1 project funding), assuming Brent USD 70 to 80 per barrel for the remainder of 2024. (3)
Three months ended 
September 30
Nine months ended 
September 30
USD Thousands 2024 2023 2024 2023
Revenue 173,200 257,366 598,659 655,446
Gross profit 39,505 93,429 167,397 210,559
Net result 22,875 71,681 101,804 143,269
Operating cash flow(3) 72,589 119,142 263,831 279,414
Free cash flow(3) (38,269) 34,703 (74,021) 67,379
EBITDA(3) 68,313 123,054 259,304 284,334
Net cash/(debt)(3) (157,228) 83,097 (157,228) 83,097
4

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
OPERATIONS REVIEW 
Business Overview
Oil prices softened in the third quarter with Brent prices averaging USD 80 per barrel compared with USD 85 per barrel in the 
second quarter. Volatility during the quarter was high with Brent prices ranging from USD 89 per barrel in July to USD 70 per barrel 
in September. Notwithstanding the volatility in prices, the crude market was in a deficit through the third quarter, aided by the 
proactive supply management by the OPEC+ group. The continued conflicts in the Middle East and Ukraine led to increased oil 
prices, though these were partially offset by concerns over global oil demand growth, in particular consumer and industrial demand 
in China. Despite some of these negative factors, the physical market remains tight with OECD crude stock levels below the 
five-year average, with oil demand expected to be at an all-time high in 2024 and continue to grow in 2025. Approximately 50% 
of IPC’s forecast 2024 oil production is hedged at USD 80 per barrel WTI or USD 85 per barrel Dated Brent through to the end of 
2024.
The third quarter 2024 WTI to Western Canadian Select (WCS) price differentials averaged just under USD 14 per barrel, in line 
with the second quarter and approximately USD 5 per barrel lower than the first quarter differential average of USD 19 per barrel. 
The Trans Mountain expansion (TMX) pipeline continues to support tighter differentials with the Western Canadian Sedimentary 
Basin (WCSB) now having excess spare pipeline capacity for the first time in more than a decade. Crude exports from the new 
TMX pipeline are flowing off the coast of British Columbia, with deliveries to the US West Coast and Asia creating new end 
destinations for Canadian heavy oil. Around 70% of our forecast 2024 Canadian WCS production volumes are hedged at a WTI/
WCS differential of USD 15 per barrel.
Natural gas prices in Canada remained supressed in the third quarter, with AECO pricing averaging CAD 0.67 per Mcf during the 
period, compared to CAD 1.17 per Mcf average for the second quarter. This has led to some Canadian natural gas producers 
curtailing production as western Canada gas storage levels continue to sit above the five-year range. IPC implemented hedges 
during the third quarter for approximately 14,500 Mcf per day at CAD 1.57 per Mcf from August to year end 2024. 
Third Quarter 2024 Highlights and Full Year 2024 Guidance
IPC delivered average daily production rates of 45,000 boepd for the third quarter. The average daily production for the first nine 
months of 2024 was 47,400 boepd and the full year Capital Markets Day (CMD) production guidance of 46,000 to 48,000 boepd 
is maintained. During the third quarter, planned maintenance shutdowns at the Onion Lake Thermal (OLT) asset in Canada and at 
the Bertam field in Malaysia were successfully completed. High uptimes were achieved across all major producing assets in our 
portfolio during the quarter and the business benefited from the oil wells drilled within our Southern Alberta assets and the new 
wells brought on stream from sustaining Pad L at the OLT asset.(1)
Operating costs in the third quarter of 2024 were below forecast at USD 17.9 per boe. The lower costs were largely driven by 
lower energy input costs within our Canadian asset base. Full year 2024 operating costs guidance is revised to less than USD 18 
per boe, below the CMD guidance range of USD 18 to 19 per boe.(3)
Operating cash flow (OCF) for the third quarter of 2024 was USD 73 million, in line with forecast.  Full year 2024 OCF guidance is 
revised to USD 335 to 342 million (assuming Brent USD 70 to 80 per barrel for the remainder of 2024).(3)
Capital and decommissioning expenditure for the third quarter was in line with plan at USD 102 million. Our full year 2024 capital 
and decommissioning expenditure guidance is unchanged at USD 437 million.
Free cash flow (FCF) was USD -38 million (or USD 44 million pre-Blackrod Phase 1 development funding) during the third quarter 
of 2024. Full year 2024 FCF guidance is revised to USD -140 to -133 million (or USD 222 to 229 million pre-Blackrod Phase 1 
development funding) assuming Brent USD 70 to 80 per barrel for the remainder of 2024.(3)
Net debt was increased during the third quarter of 2024 by approximately USD 69 million to USD 157 million.(3) This is due to the 
growth capital expenditure at the Blackrod Phase 1 project and continued funding of the normal course issuer bid (NCIB) share 
repurchase program. The gross cash position as at September 30, 2024 was USD 299 million. In the third quarter, IPC enhanced 
its financing position by entering into a letter of credit facility in Canada to cover all of its existing operational letters of credit, giving 
full availability under IPC’s undrawn CAD 180 million Revolving Credit Facility.
With a robust balance sheet and strong cashflow generation from the producing assets, IPC is strongly positioned to deliver on our 
three strategic pillars of organic growth, shareholder returns and pursue value-adding M&A.
5

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Blackrod Phase 1 Project
The Blackrod asset is 100% owned by IPC and hosts the largest booked reserves and contingent resources within the IPC 
portfolio. After more than a decade of pilot operations, subsurface delineation and commercial engineering studies, IPC sanctioned 
the Phase 1 development in the first quarter of 2023. The Phase 1 development targets 218 MMboe of 2P reserves, with a multi-
year forecast capital expenditure of USD 850 million to first oil planned in late 2026. The Phase 1 development is planned for 
plateau production of 30,000 bopd which is expected by early 2028. (1)(2) 
2024 marks a peak investment year at the Blackrod Phase 1 project for IPC, with USD 362 million planned to be spent in the year. 
Project progress has advanced according to plan, with approximately USD 245 million spent through the first nine months of 2024. 
All major third-party contracts have been executed, including but not limited to, the engineering, procurement and construction 
(EPC) agreements for the central processing facility (CPF) and well pad facilities, midstream agreements for the input fuel gas, 
diluent and oil blend pipelines, and drilling rig and stakeholder agreements. All major long lead items have been procured and
pre-operations onboarding continues as the asset undergoes rapid change from a pilot steam assisted gravity drainage (SAGD) 
operation to a commercial SAGD operation. IPC’s core operational philosophy is to responsibly develop and commission projects 
with the staff that are going to manage and operate the asset to ensure the seamless transition from development to operations.
As at the end of the third quarter of 2024, over half of the Blackrod Phase 1 development capital had been spent since the project 
sanction in early 2023. All major work streams are progressing as planned and the focus continues to be on executing the detailed 
sequencing of events as facility modules are safely delivered and installed at site. The total Phase 1 project guidance of USD 850 
million capital expenditure to first oil in late 2026 is unchanged. IPC intends to fund the remaining Blackrod Phase 1 development 
costs with forecast cash flow generated by its operations and cash on hand.
Stakeholder Returns: Normal Course Issuer Bid
Under the current 2023/2024 NCIB, IPC has the ability to repurchase up to approximately 8.3 million common shares over the 
period of December 5, 2023 to December 4, 2024. IPC repurchased and cancelled approximately 7.5 million common shares up 
to the end of September 2024. The average price of common shares purchased under the 2023/2024 NCIB was SEK 132/CAD 17 
per share. IPC expects to complete the 2023/2024 NCIB during November 2024, resulting in the cancellation of 6.5% of the total 
number of common shares outstanding as at the beginning of December 2023.
As at September 30, 2024, IPC had a total of 120,751,038 common shares issued and outstanding and IPC held 30,000 common 
shares in treasury. As at October 31, 2024, IPC had a total of 120,244,638 common shares issued and outstanding and IPC held 
44,400 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 2024 to December 2025. We expect that the 2024/2025 NCIB will permit 
IPC to purchase on the TSX and/or Nasdaq Stockholm, and cancel, up to a further approximately 7.5 million common shares, 
representing approximately 6.2% of the total outstanding common shares (or 10% of IPC’s “public float” under applicable TSX 
rules) following completion of the current 2023/2024 NCIB. IPC continues to believe that reducing the number of common shares 
outstanding while in parallel investing in material production growth at the Blackrod project will prove to be a winning formula for 
our stakeholders.
Environmental, Social and Governance (ESG) Performance
As part of IPC’s commitment to operational excellence and responsible development, its objective is to reduce risk and eliminate 
hazards to prevent occurrence of accidents, ill health, and environmental damage, as these are essential to the success of our 
business operations. During the third quarter of 2024, IPC recorded no material safety or environmental incidents.  
As previously announced, IPC targets a reduction of our net GHG emissions intensity by the end of 2025 to 50% of IPC’s 2019 
baseline and IPC remains on track to achieve this reduction. During the first quarter of 2024, IPC announced the commitment to 
remain at end 2025 levels of 20 kg CO2/boe through to the end of 2028.(4)
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, 2023 (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, including assumptions relating to the calculation of NPV, are described in the AIF .  
(3) Non-IFRS measures, see “Non-IFRS Measures” below and in the MD&A.
(4) Emissions intensity is the ratio between oil and gas production and the associated carbon emissions, and net emissions 
intensity reflects gross emissions less operational emission reductions and carbon offsets.
6

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Operations Overview 
Q3 2024 Overview
In Q3 2024, IPC continued to successfully demonstrate its commitment to operational excellence, with strong operational 
performance and no material safety or environmental incidents. 
In Canada, the Blackrod Phase 1 development project is progressing in line with schedule and budget. As at the end of Q3 2024, 
process facility fabrication is on track supporting critical equipment site installation which continues to progress in line with plan. 
Site civil works and access road upgrades are largely complete while production well pad drilling continues to progress ahead of 
schedule. 
At our producing assets in Canada, strong operational performance has been maintained during a period of planned maintenance 
shutdown activity and lower gas production due to reduced optimization activity on the back of lower gas pricing. At the Bertam 
field in Malaysia, average daily production remained strong in Q3 2024, with high production uptime and a continued focus on well 
rate optimization activity to offset natural declines. In France, stable production performance continues at the major producing 
assets.
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 468 MMboe as at December 31, 2023, as certified by independent 
third party reserve auditors. The proved plus probable reserve life index (RLI) as at December 31, 2023, is approximately 27 years. 
Best estimate contingent resources as at December 31, 2023, are 1,145 MMboe (unrisked). See “Reserves and Resources 
Advisory” below. 
In 2024, as we embarked on the peak spend year at our exciting Blackrod Phase 1 development, IPC set out a balanced base 
business (non-Blackrod) capital expenditure budget for the year. IPC remains focused on organic growth and continues to mature 
future development projects across all operated assets, with a significant portfolio of drilling and optimization opportunities ready 
for sanction at the discretion of the Group.
Production
Average daily net production for Q3 2024 was in line with the 2024 Capital Markets Day Guidance at 45,000 boepd. 
With strong operational delivery through the first nine months of 2024, IPC is on target to deliver annual net average daily 
production within the guidance range of 46,000 to 48,000 boepd.   
The production during Q3 2024 with comparatives is summarized below:
Production
in Mboepd
Three months ended
September 30
Nine months ended
September 30
Year ended
December 31
2024 2023 2024 2023 2023
Crude oil
Canada – Northern Assets 12.7 15.8 14.0 15.6 15.5
Canada – Southern Assets1 10.9 11.4 11.1 11.9 11.8
Malaysia 3.7 2.9 4.0 4.3 3.8
France 2.4 2.8 2.5 2.7 2.8
Total crude oil production 29.7 32.9 31.6 34.5 33.9
Gas
Canada – Northern Assets 0.4 0.3 0.4 0.3 0.4
Canada – Southern Assets 14.9 17.0 15.4 16.8 16.8
Total gas production 15.3 17.3 15.8 17.1 17.2
Total production 45.0 50.2 47.4 51.6 51.1
Quantity in MMboe 4.14 4.62 12.98 14.09 18.65
1 In respect of 2023 production, includes production from the Brooks assets acquired in the Cor4 acquisition in the Suffield area from January 1, 
2023 being the effective date of the Cor4 acquisition. The acquisition of Cor4 was completed on March 3, 2023. 
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
7

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
CANADA
Production
in Mboepd
Working 
Interest
(WI)
Three months ended
September 30
Nine months ended
September 30
Year ended
December 31
2024 2023 2024 2023 2023
- Oil Onion Lake Thermal 100% 10.7 13.4 12.4 13.2 13.3
- Oil Suffield Area1 100% 9.2 10.0 9.7 10.3 10.2
- Oil Other 50-100% 3.7 3.8 3.0 4.0 3.8
- Gas1 ~100% 15.3 17.3 15.8 17.1 17.2
Canada 38.9 44.5 40.9 44.6 44.5
1  In respect of 2023 production, includes production from the Brooks assets acquired in the Cor4 acquisition in the Suffield area from January 1, 
2023 being the effective date of the Cor4 acquisition. The acquisition of Cor4 was completed on March 3, 2023. 
 
Production
Net production from IPC’s assets in Canada during Q3 2024 was in line with guidance at 38,900 boepd. Strong operational 
performance has been maintained despite lower gas production rates with a reduction in optimization activity on the back of 
softer gas sales pricing. The planned maintenance shutdown at Onion Lake Thermal was successfully and safely delivered in line 
with plan. The 2024 capital development investments continue to deliver strong results with the three new Ferguson asset wells 
performing ahead of expectations and positive production indications at the Mooney Phase 2 EOR project.    
Organic Growth and Capital Projects
In Canada, with the Blackrod Phase 1 project development in its most capital intensive phase, IPC announced a minimum non 
Blackrod  capital expenditure budget for 2024. At our Southern assets, the focus remains on the high performing Suffield Ellerslie 
play and is supplemented with the next phase of development well drilling at our Ferguson asset. At Onion Lake Thermal, 
production rate optimization is the priority with a continued phased ramp up of the latest production sustaining Pad L planned.
During Q3 2024, the Blackrod Phase 1 project development continued to progress in line with expectations. As at the end of Q3 
2024, process facility fabrication and critical equipment site installation is progressing in line with schedule, site civil and road 
expansion activities are largely complete while utility well and Well Pad drilling is progressing ahead of plan. 
At Ferguson, the three newly drilled oil production wells continue to deliver strong results above expectations.
During Q3 2024, on the back of positive results from the Suffield area Ellerslie well drilling to date, IPC management sanctioned 
three additional Ellerslie well drills increasing the 2024 Ellerslie drilling budget from the original five to eight well targets in the year. 
As of the end of Q3 2024, seven Ellerslie wells have been drilled with five wells online and performing in line with expectations. 
At Onion Lake Thermal, daily production has remained stable with six production sustaining Pad L well pairs online. The seventh 
Pad L well is scheduled to be brought online in Q4 2024. 
MALAYSIA
Production
in Mboepd WI
Three months ended
September 30
Nine months ended
September 30
Year ended
December 31
2024 2023 2024 2023 2023
Bertam 100% 3.7 2.9 4.0 4.3 3.8
Production
Net production at Bertam in Malaysia in Q3 2024 was in line with guidance at 3,700 boepd with high production uptime and a 
continued focus on well rate optimization activity to offset natural declines.
Organic Growth and Capital Projects
In Malaysia, field development studies have progressed in line with expectations as IPC matures the remaining undeveloped 
potential of the Bertam field.  
8

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
FRANCE
Production
in Mboepd WI
Three months ended
September 30
Nine months ended
September 30
Year ended
December 31
2024 2023 2024 2023 2023
France
- Paris Basin 100%1 2.1 2.5 2.2 2.3 2.4
- Aquitaine 50% 0.3 0.3 0.3 0.4 0.4
2.4 2.8 2.5 2.7 2.8
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q3 2024 was at 2,400 boepd with stable performance at all the major producing assets.   
Organic Growth
IPC continues to mature future development projects in France, with focus towards the undeveloped resource base within the 
Paris Basin supported by the positive results following the 2023 development campaign.
9

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
FINANCIAL REVIEW 
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q3-24 Q2-24 Q1-24 Q4-23 Q3-23 Q2-23 Q1-23 Q4-22
Revenue 173,200 219,040 206,419 198,460 257,366 205,564 192,516 254,615
Gross profit 39,505 72,708 55,184 39,955 93,429 52,747 64,383 95,411
Net result 22,875 45,210 33,719 29,710 71,681 32,025 39,563 61,183
Earnings per share – USD 0.19 0.36 0.27 0.23 0.56 0.24 0.29 0.45
Earnings per share fully
diluted – USD 0.18 0.36 0.26 0.22 0.54 0.24 0.28 0.44
Operating cash flow1 72,589 101,941 89,301 73,634 119,142 84,372 75,900 113,668
Free cash flow1 (38,269) 7,559 (43,311) (64,688) 34,703 16,415 16,259 65,288
EBITDA1 68,313 103,971 87,020 66,284 123,054 85,201 76,079 125,651
Net cash/(debt) at period end1 (157,228) (88,220) (60,572) 58,043 83,097 63,548 66,956 175,098
1  See definition on page 19 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands September 30, 2024 December 31, 2023
Non-current assets 1,550,935 1,372,388
Current assets 456,253 690,597
Total assets 2,007,188 2,062,985
Total non-current liabilities 806,864 779,838
Current liabilities 156,318 202,888
Total liabilities 963,182 982,726
Net assets 1,044,006 1,080,259
Working capital (including cash) 299,935 487,709
10

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Selected Interim Financial Information
The Group operates within several geographical areas. Operating segments are reported at a country level, with Canada being 
further analyzed by main areas: (i) Canada – Northern Assets (comprising mainly of the Onion Lake Thermal asset) and (ii) Canada –
Southern Assets (comprising mainly of the Suffield assets, including the Brooks assets). This is consistent with the internal 
reporting provided to IPC management. The following tables present certain segment information.
Three months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 88,579 68,544 17,876 15,939 – 190,938
NGLs – 243 – – – 243
Gas 26 3,863 – – – 3,889
Net sales of oil and gas 88,605 72,650 17,876 15,939 – 195,070
Change in under/over lift position – – – 1,289 – 1,289
Royalties (15,693) (11,911) – (1,164) – (28,768)
Hedging settlement 2,934 2,432 – – – 5,366
Other operating revenue – – – 216 27 243
Revenue 75,846 63,171 17,876 16,280 27 173,200
Operating costs (20,546) (36,412) (9,140) (7,823) – (73,921)
Cost of blending (24,113) (5,705) – – – (29,818)
Change in inventory position 369 (699) 3,516 (431) – 2,755
Depletion and decommissioning 
costs (8,204) (12,888) (6,285) (3,114) – (30,491)
Depreciation of other tangible 
fixed assets – – (2,023) – – (2,023)
Exploration and business
development costs – – – – (197) (197)
Gross profit/(loss) 23,352 7,467 3,944 4,912 (170) 39,505
Three months ended – September 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 124,468 77,045 46,148 19,318 – 266,979
NGLs – 377 – – – 377
Gas 98 16,607 – – – 16,705
Net sales of oil and gas 124,566 94,029 46,148 19,318 – 284,061
Change in under/over lift position – – – 4,349 – 4,349
Royalties (19,712) (12,261) – (1,239) – (33,212)
Hedging settlement (985) 2,839 – – – 1,854
Other operating revenue – – – 229 85 314
Revenue 103,869 84,607 46,148 22,657 85 257,366
Operating costs (22,466) (40,330) (11,062) (9,004) – (82,862)
Cost of blending (32,858) (6,978) – – – (39,836)
Change in inventory position (151) 466 (8,478) 96 – (8,067)
Depletion and decommissioning 
costs (9,687) (14,906) (3,438) (3,656) – (31,687)
Depreciation of other tangible 
fixed assets – – (1,509) – – (1,509)
Exploration and business
development costs – – – – 24 24
Gross profit/(loss) 38,707 22,859 21,661 10,093 109 93,429
11

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Nine months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 308,206 209,551 75,770 49,909 – 643,436
NGLs – 762 – – – 762
Gas 195 24,786 – – – 24,981
Net sales of oil and gas 308,401 235,099 75,770 49,909 – 669,179
Change in under/over lift position – – – 6,420 – 6,420
Royalties (53,565) (32,811) – (3,464) – (89,840)
Hedging settlement 6,666 5,262 – – – 11,928
Other operating revenue – – – 670 302 972
Revenue 261,502 207,550 75,770 53,535 302 598,659
Operating costs (60,464) (106,184) (23,385) (24,538) – (214,571)
Cost of blending (97,283) (19,416) – – – (116,699)
Change in inventory position 737 (1,024) 3,726 (279) – 3,160
Depletion and decommissioning 
costs1 (27,413) (39,069) (20,208) (9,615) – (96,305)
Depreciation of other tangible 
fixed assets – – (6,503) – – (6,503)
Exploration and business
development costs – – – – (344) (344)
Gross profit/(loss) 77,079 41,857 29,400 19,103 (42) 167,397
Nine months ended – September 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 324,963 196,420 85,924 52,476 – 659,783
NGLs – 845 – – – 845
Gas 255 52,309 – – – 52,564
Net sales of oil and gas 325,218 249,574 85,924 52,476 – 713,192
Change in under/over lift position – – – 8,842 – 8,842
Royalties (45,495) (30,218) – (3,575) – (79,288)
Hedging settlement (1,620) 13,589 – – – 11,969
Other operating revenue – 7 – 639 85 731
Revenue 278,103 232,952 85,924 58,382 85 655,446
Operating costs (70,949) (116,527) (26,509) (24,609) – (238,594)
Cost of blending (108,603) (19,920) – – – (128,523)
Change in inventory position 190 79 2,141 (182) – 2,228
Depletion and decommissioning 
costs1 (15,804) (30,481) (14,818) (10,385) – (71,488)
Depreciation of other tangible 
fixed assets – – (6,503) – – (6,503)
Exploration and business
development costs – (834) – (9) (1,164) (2,007)
Gross profit/(loss) 82,937 65,269 40,235 23,197 (1,079) 210,559
1  In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program.
12

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Three and nine months ended September 30, 2024, Review 
Revenue
Total revenue amounted to USD 173,200 thousand for Q3 2024, compared to USD 257,366 thousand for Q3 2023 and USD
598,659 thousand for the first nine months of 2024 compared to USD 655,446 thousand for the first nine months of 2023 and is
analyzed as follows: 
USD Thousands 
Three months ended
September 30
Nine months ended
September 30
2024 2023 2024 2023
Crude oil sales 190,938 266,979 643,436 659,783
Gas and NGL sales 4,132 17,082 25,743 53,409
Change in under/overlift position 1,289 4,349 6,420 8,842
Royalties (28,768) (33,212) (89,840) (79,288)
Hedging settlement 5,366 1,854 11,928 11,969
Other operating revenue 243 314 972 731
Total revenue 173,200 257,366 598,659 655,446
The main components of total revenue for the three and nine months ended September 30, 2024, and September 30, 2023, 
respectively, are detailed below. 
Crude oil sales
Three months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 88,579 68,544 17,876 15,939 190,938
- Quantity sold in bbls 1,446,627 1,107,248 221,082 198,101 2,973,058
- Average price realized USD per bbl 61.23 61.90 80.86 80.46 64.22
Three months ended – September 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 124,468 77,045 46,148 19,318 266,979
- Quantity sold in bbls 1,814,151 1,116,530 486,962 223,481 3,641,124
- Average price realized USD per bbl 68.61 69.00 94.77 86.44 73.32
Crude oil revenue was 28% lower in Q3 2024 compared to Q3 2023 due to lower sales volumes and lower oil prices. Canadian - 
Northern Assets sales volumes are 20% lower in Q3 2024 compared to Q3 2023 as a result of a planned maintenance shutdown 
at Onion Lake Thermal in September 2024.
The Suffield area assets and Onion Lake Thermal crude oil in Canada is blended with purchased condensate diluent volumes  to 
meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada. 
The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q3 2024, WTI averaged USD 75 per bbl compared to USD 82 per bbl for Q3 2023 and the 
average discount to WCS used in IPC’s pricing formula was USD 14 per bbl compared to USD 13 per bbl for Q3 2023.
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 2024 and two cargo liftings in Q3 2023. Produced unsold oil barrels from Bertam at the end of Q3 2024 amounted to 
232,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 80 per bbl for 
Q3 2024 compared to USD 87 per bbl for the comparative period.
13

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Nine months ended – September, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 308,206 209,551 75,770 49,909 643,436
- Quantity sold in bbls 5,012,498 3,353,780 845,411 602,713 9,814,402
- Average price realized USD per bbl 61.49 62.48 89.63 82.81 65.56
Nine months ended – September, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 324,963 196,420 85,924 52,476 659,783
- Quantity sold in bbls 5,525,405 3,248,704 932,654 640,586 10,347,349
- Average price realized USD per bbl 58.81 60.46 92.13 81.92 63.76
The Suffield area assets and Onion Lake crude oil in Canada are blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada. 
Crude oil revenue were lower by 2% during the first nine months of 2024 compared to the first nine months of 2023 mainly due 
to lower sales volumes partly offset by higher prices. Canadian - Northern Assets sales volumes are 9% lower during the first nine 
months of 2024 compared to the first nine months of 2023 mainly as a result of a planned maintenance shutdown at Onion Lake 
Thermal in September 2024. In addition, Canadian – Southern Assets sales volumes are 3% higher in the first nine months 2024 
compared to the first nine months of 2023 as a result of the Brooks assets acquisition in March 2023.
The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. For the first nine months of 2024, 
WTI averaged USD 77 per bbl compared to USD 77 per bbl for the comparative period and the average discount to WCS used in 
our pricing formula was USD 15 per bbl compared to USD 18 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 83 per bbl for the first nine months of 2024 compared to USD 82 per bbl for the comparative period.
Gas and NGL sales
Three months ended – September 30, 2024
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 26 4,106 4,132
- Quantity sold in Mcf 74,249 7,335,019 7,409,268
- Average price realized USD per Mcf 0.35 0.56 0.56
Three months ended – September 30, 2023
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 98 16,984 17,082
- Quantity sold in Mcf 55,178 8,541,601 8,596,779
- Average price realized USD per Mcf 1.77 1.99 1.99
Gas and NGL sales revenue was 76% lower for Q3 2024 compared to Q3 2023 mainly due to the lower achieved gas price. IPC’s 
achieved gas price is based on AECO pricing plus a premium. For Q3 2024, IPC realized an average price of CAD 0.72 per Mcf 
compared to AECO average pricing of CAD 0.67 per Mcf. 
14

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Nine months ended – September 30, 2024
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 195 25,548 25,743
- Quantity sold in Mcf 208,107 22,810,152 23,018,259
- Average price realized USD per Mcf 0.94 1.12 1.12
Nine months ended – September 30, 2023
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 255 53,154 53,409
- Quantity sold in Mcf 149,847 24,635,855 24,785,702
- Average price realized USD per Mcf 1.70 2.16 2.15
Gas and NGL sales revenue was 52% lower for the first nine months of 2024 compared to the first nine months of 2023 mainly 
due to the lower achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For the first nine months of 2024, IPC realized an average price 
of CAD 1.49 per Mcf compared to AECO average pricing of CAD 1.45 per Mcf.
Hedging settlement
IPC enters into risk management contracts in order to ensure a certain level of cash flow. It focuses mainly on oil and gas price 
swaps to limit pricing exposure. Oil and gas pricing contracts are not entered into for speculative purposes. 
The realized hedging settlement for the first nine months of 2024 amounted to a gain of USD 11,928 thousand and consisted of 
a gain of USD 11,255 thousand on the oil contracts and a gain of USD 673 thousand on the gas contracts. Also see the Financial 
Position and Liquidity and the Financial Risk Management sections below.
Production costs
Production costs including inventory movements amounted to USD 100,984 thousand for Q3 2024 compared to USD 130,765 
thousand for Q3 2023 and USD 328,110 thousand for the first nine months of 2024 compared to USD 364,889 thousand for the
comparative period, and is analyzed as follows:
Three months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 20,546 36,412 13,235 7,823 (4,095) 73,921
USD/boe2 17.07 15.35 39.27 34.99 n/a 17.87
Cost of blending 24,113 5,705 – – – 29,818
Change in inventory position (369) 699 (3,516) 431 – (2,755)
Production costs 44,290 42,816 9,719 8,254 (4,095) 100,984
Three months ended – September 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 22,466 40,330 14,349 9,004 (3,287) 82,862
USD/boe2 15.19 15.46 53.25 34.64 n/a 17.95
Cost of blending 32,858 6,978 – – – 39,836
Change in inventory position 151 (466) 8,478 (96) – 8,067
Production costs 55,475 46,842 22,827 8,908 (3,287) 130,765
15

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Nine months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 60,464 106,184 35,670 24,538 (12,285) 214,571
USD/boe2 15.28 14.65 32.92 35.65 n/a 16.53
Cost of blending 97,283 19,416 – – – 116,699
Change in inventory position (737) 1,024 (3,726) 279 – (3,160)
Production costs 157,010 126,624 31,944 24,817 (12,285) 328,110
Nine months ended – September 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 70,949 116,527 37,941 24,609 (11,432) 238,594
USD/boe2 16.31 15.75 32.67 33.14 n/a 17.42
Cost of blending 108,603 19,920 – – – 128,523
Change in inventory position (190) (79) (2,141) 182 – (2,228)
Production costs 179,362 136,368 35,800 24,791 (11,432) 364,889
1  See definition on page 19 under “Non-IFRS measures”.
2  USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and for 2023, includes the 
Brooks assets from January 1, 2023.
3  Included in the Malaysia operating costs is the lease cost for the FPSO Bertam which is owned by the Group. Other represents the FPSO Bertam
 lease fee self-to-self payment elimination. Netting the self-to-self elimination against the operating costs in Malaysia reduces the operating costs
 per boe for Malaysia to USD 27.12 for Q3 2024 and USD 41.06 for the comparative period and USD 21.58 and USD 22.83 for the nine months
 ended September 30, 2024, and September 30, 2023, respectively.
Operating costs
Operating costs amounted to USD 73,921 thousand for Q3 2024 compared to USD 82,862 thousand for Q3 2023 and USD 
214,571 thousand for the first nine months of 2024 compared to USD 238,594 thousand for the first nine months of 2023. 
Operating costs per boe amounted to USD 17.87 per boe in Q3 2024 below guidance for the quarter and compared with USD 
17.95 per boe in Q3 2023. 
Cost of blending
For the Suffield area and Onion Lake Thermal assets in Canada, oil production is blended with purchased condensate diluent to 
meet pipeline specifications. As a result of the blending, actual sales volumes are higher than produced barrels and the realized 
sales price of a blended barrel is higher than an unblended barrel. 
The cost of the diluent amounted to USD 29,818 thousand for Q3 2024 compared to USD 39,836 thousand for Q3 2023 and USD 
116,699 thousand for the first nine months of 2024 compared to USD 128,523 thousand for the comparative period. The decrease 
of the diluent in Q3 2024 compared to Q3 2023 is due mainly to lower production at Onion Lake Thermal as a consequence of a 
planned maintenance shutdown.
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 2024, IPC had crude entitlement of 232,000 barrels of oil on the FPSO Bertam facility 
being crude produced but not yet sold. 
Depletion and decommissioning costs
The total depletion of oil and gas properties amounted to USD 30,491 thousand for Q3 2024 compared to USD 31,687 thousand 
for Q3 2023 and USD 96,305 thousand for the first nine months of 2024 compared to USD 71,488 thousand for the first nine 
months of 2023 (including an adjustment for accelerated decommissioning activities amounting to USD 24,055 thousand). 
16

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
The depletion charge is analyzed in the following tables:
Three months ended – September 30, 2024
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 8,204 12,888 6,285 3,114 30,491
USD per boe 6.82 5.43 18.65 13.93 7.37
Three months ended – September 30, 2023
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,687 14,906 3,438 3,656 31,687
USD per boe 6.55 5.71 12.76 14.07 6.86
Nine months ended – September 30, 2024
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands1 27,413 39,069 20,208 9,615 96,305
USD per boe2 6.93 5.39 18.65 13.97 7.42
Nine months ended – September 30, 2023
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands1 28,115 42,225 14,818 10,385 95,543
USD per boe2 6.46 5.70 12.76 13.99 6.96
1  In Canada, excludes the adjustment for accelerated decommissioning activities.
2  USD/boe in the tables above is calculated by dividing the depletion cost by the production volume for each country for the period and for 2023, 
includes the Brooks assets from January 1, 2023.
The depletion charge is derived by applying the depletion rate per boe to the volumes produced in the period by each field. The 
depletion rate in Malaysia has significantly increased compared to the prior year following the capitalization of the workover costs 
incurred in Q4 2023 and Q1 2024. 
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 2,023 thousand for Q3 2024 compared to USD 1,509 thousand for Q3 
2023 and USD 6,503 thousand for the first nine months of 2024 compared to USD 6,503 thousand for the first nine months of 
2023. This relates to the depreciation of the FPSO Bertam, which is being depreciated to its residual value on a unit of production 
basis to August 2025.
Exploration and business development costs
The total exploration and business developments costs amounted to a cost of USD 344 thousand for the first nine months of 2024 
and  a cost of USD 2,007 thousand for the first nine months of 2023 which included the Brooks assets acquisition related costs 
amounting to USD 834 thousand.
Net financial items
Net financial items amounted to a charge of USD 4,124 thousand for Q3 2024, compared to a charge of USD  4,257 thousand for 
Q3 2023 and a charge of USD 23,942 thousand for the first nine months of 2024 compared to a charge of USD 16,227 thousand 
for the first nine months of 2023, and included a largely non-cash net foreign exchange gain of USD 1,743 thousand for the first 
nine months of 2024 compared to a net foreign exchange loss of USD 1,493 thousand for the first nine months of 2023. The 
foreign exchange movements are mainly resulting from the revaluation of intra-group loan funding balances.
Excluding foreign exchange movements, the net financial items amounted to a charge of USD 9,484 thousand for Q3 2024, 
compared to USD 5,111 thousand for Q3 2023 and a charge of USD 25,685 thousand for the first nine months of 2024 compared 
to a charge of 14,734 thousand for the comparative period.  
17

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
The interest expense amounted to USD 9,119 thousand for Q3 2024, compared to USD  5,787 thousand for the comparative 
period in 2023 and USD 26,865 thousand for the first nine months of 2024 compared to USD 16,591 thousand for the first nine 
months of 2023 and mainly related to the bond interest at a coupon rate of 7.25% per annum. The increase compared to the 
comparative period is largely attributable to the additional MUSD 150 bond tap issue completed in Q3 2023. Interest income 
generated on cash balances held amounted to USD 4,112 thousand for Q3 2024 and USD 14,646 thousand for the first nine 
months of 2024 and USD 4,979 thousand for Q3 2023 and USD 14,238 thousand for the first nine months of 2023.
The unwinding of the asset retirement obligation discount rate amounted to USD 3,680 thousand for Q3 2024, compared to USD  
3,479 thousand for the comparative period and USD 10,939 thousand for the first nine months of 2024 compared to USD 10,021 
thousand for the first nine months of 2023. 
Income tax
The corporate income tax amounted to a charge of USD 8,257 thousand for Q3 2024, compared to a charge of USD 25,451 
thousand for the comparative period and a charge of USD 29,473 thousand for the first nine months of 2024 compared to a charge 
of USD 50,671 thousand for the comparative period. 
The current income tax amounted to a credit of USD 373 thousand for Q3 2024  and a charge of USD 6,718 thousand during the 
first nine months of 2024 and mainly related to France and Malaysia. No corporate income tax is expected to be payable in Canada 
in 2024 due to the usage of historical tax pools. 
Capital Expenditure
Development and exploration and evaluation expenditure incurred during the first nine months of 2024 was as follows:
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 257,726 30,234 16,372 2,691 307,023
Exploration and evaluation 352 – 1,082 – 1,434
258,078 30,234 17,454 2,691 308,457
Capital expenditure of USD 307,023 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project, drilling 
on the Ferguson and Brooks assets and in Malaysia on the well workovers.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 18,938 thousand as at September 30, 2024, which included USD 17,227 thousand in 
respect of the FPSO Bertam. The FPSO Bertam is being depreciated on a unit of production basis based to August 2025, being the 
original Bertam field PSC expiry date before the PSC extension to 2035.
Financial Position and Liquidity
Financing 
As at January 2023, IPC had MUSD 300 of bonds outstanding, issued in February 2022 and maturing in February 2027 with a fixed 
coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group also had a revolving 
credit facility of MCAD 75 (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In Q3 2023, IPC completed a tap issue of MUSD 150 under IPC’s existing 7.25% bond framework issued at 7% discount to par 
value with proceeds amounting to MUSD 139.5 before transaction costs. For accounting purposes, the discounted amount was 
recognised in the balance sheet and the discount will be unwound over the period to maturity of the bond and charged to the 
interest expense line of the Statement of Operations using the effective interest rate methodology. As at September 30, 2024, IPC 
had a nominal MUSD 450 of bonds outstanding with maturity in February 2027. The bond repayment obligations as at September 
30, 2024, are classified as non-current as there are no mandatory repayments within the next twelve months.
During 2023, the Group increased the Canadian RCF from MCAD 75 to MCAD 180 with a maturity to May 2025. During Q2 
2024, the Group extended the maturity of the Canadian RCF to May 2026. The Canadian RCF is undrawn and fully available as 
at September 30, 2024. During Q3 2024, the Group entered into a letter of credit facility in Canada (the “LC Facility”) to cover 
existing operational letters of credit. As at September 30, 2024, operational letters of credit in an aggregate of MCAD 40.2 have 
been issued under the LC Facility, including letters of credit issued in Q2 2024 for a total amount of MCAD 35 to support the third 
party pipeline construction agreements for the Blackrod project during 2024 and 2025.
As at September 30, 2024, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May 
2026. IPC makes quarterly repayments of the French Facility and the amount remaining outstanding under the France Facility 
as at September 30, 2024 was MUSD 6. An amount of MUSD 3.5 drawn under the France Facility as at September 30, 2024 is 
classified as current representing the repayment planned within the next twelve months.
18

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
The Group is in compliance with the covenants of the bonds and its financing facilities as at September 30, 2024. 
Net debt as at September 30, 2024 amounted to MUSD 157. Cash and cash equivalents held amounted to MUSD 299 as at 
September 30, 2024.
IPC intends to fund the remaining Blackrod Phase 1 project development costs with cash on hand and forecast cash flow 
generated by its operations.
Working Capital 
As at September 30, 2024, the Group had a working capital balance including cash of USD 299,935 thousand compared to USD 
487,709 thousand as at December 31, 2023. The difference as at September 30, 2024, from December 31, 2023, is mainly as a 
result of the decreased cash following capital expenditures on the Blackrod Phase 1 development project and the continuing NCIB 
program. 
Non-IFRS Measures
In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free
cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do 
not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by 
other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in 
accordance with IFRS.
The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by and
the financial performance and condition of the Corporation. Management also uses non-IFRS measures internally in order to
facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s
ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures
are important supplemental measures of operating performance because they highlight trends in the core business that may
not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for
assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable
between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties
frequently use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the
purpose of presenting information about management’s current expectations and plans relating to the future and readers are
cautioned that such statements may not be appropriate for other purposes.
“Operating cash flow” is calculated as revenue less production costs less current tax. Operating cash flow is used to analyze the
amount of cash that is being generated available for capital investment and servicing debt.
“Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures
less general, administration and depreciation expenses before depreciation and less cash financial items. Free cash flow is used
to analyze the amount of cash that is being generated by the business and that is available for such purposes as repaying debt,
funding acquisitions and returning capital to shareholders.
“EBITDA” is calculated as net result before financial items, taxes, depletion of oil and gas properties, exploration costs,
impairment costs and depreciation and adjusted for non-recurring profit/loss on sale of assets and other income.
“Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is
used to analyze the cash cost of producing the oil and gas volumes.
“Net debt” is calculated as bank loans and bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash 
equivalents less bank loans and bonds. 
Reconciliation of Non-IFRS Measures
Operating cash flow
The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended
September 30
Nine months ended
September 30
2024 2023 2024 2023
Revenue 173,200 257,366 598,659 655,446 
Production costs (100,984) (130,765) (328,110) (364,889)
Current tax 373 (7,459) (6,718) (16,045)
Operating cash flow 72,589 119,142 263,831 274,512 
The operating cash flow for the nine months ended September 30, 2023 including the operating cash flow contribution of the 
Brooks assets acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 
279,414 thousand. 
19

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
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
2024 2023 2024 2023
Operating cash flow - see above 72,589 119,142 263,831 274,512 
Capital expenditures (99,100) (76,844) (308,457) (183,904)
Abandonment and farm-in expenditures1 (2,575) (2,755) (4,938) (7,683)
General, administration and depreciation expenses before 
depreciation2 (3,903) (3,547) (11,245) (11,124)
Cash financial items3 (5,280) (1,293) (13,212) (3,593)
Free cash flow (38,269) 34,703 (74,021) 68,208 
1  See note 16 to the Financial Statements 
2  Depreciation is not specifically disclosed in the Financial Statements
3  See notes 4 and 5 to the Financial Statements.
The free cash flow for the nine months ended September 30, 2023 including the free cash flow contribution of the Brooks 
assets acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 67,379 
thousand. 
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended
September 30
Nine months ended
September 30
2024 2023 2024 2023
Net result 22,875 71,681 101,804 143,269 
Net financial items 4,124 4,257 23,942 16,227 
Income tax 8,257 25,451 29,473 50,671 
Depletion and decommissioning costs 30,491 31,687 96,305 71,488 
Depreciation of other tangible fixed assets 2,023 1,509 6,503 6,503 
Exploration and business development costs 197 (24) 344 2,007 
Depreciation included in general, administration and depreciation 
expenses1 346 405 933 1,180 
Sale of assets – (11,912) – (11,912)
EBITDA 68,313 123,054 259,304 279,433
1  Item is not shown in the Financial Statements.
The EBITDA for the nine months ended September 30, 2023 including the EBITDA contribution of the Brooks assets acquisition 
from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 284,334 thousand. 
Operating costs
The following table sets out how operating costs is calculated: 
USD Thousands
Three months ended
September 30
Nine months ended
September 30
2024 2023 2024 2023
Production costs 100,984 130,765 328,110 364,889 
Cost of blending (29,818) (39,836) (116,699) (128,523)
Change in inventory position 2,755 (8,067) 3,160 2,228 
Operating costs 73,921 82,862 214,571 238,594 
The operating costs for the nine months ended September 30, 2023 including the operating costs contribution of the Brooks 
assets acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 245,395 
thousand. 
20

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Net cash/(debt)
The following table sets out how net cash/(debt) is calculated: 
USD Thousands September 30, 2024 December 31, 2023
Bank loans (6,431) (9,031)
Bonds1 (450,000) (450,000)
Cash and cash equivalents 299,203 517,074 
Net cash/(debt) (157,228) 58,043
1  The bond amount represents the redeemable value at maturity (February 2027).  
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, has issued six letters of credit as follows: (a) MCAD 2.6 in respect of its obligations to 
purchase diluent; (b) MCAD 0.9 in respect of its obligations related to the Ferguson asset, increasing by  MCAD 0.1 annually to a 
maximum of MCAD 1.0; (c) MCAD 1.3 in respect of pipeline access; (d) MCAD 0.5 in relation to the hedging of electricity prices; 
(e) and (f) MCAD 24.5 and MCAD 10.5 respectively in respect of its obligations related to Blackrod pipelines. 
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, 2023, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in 
treasury.
Over the period of January 1, 2024 to September 30, 2024, IPC purchased a total of 6,271,028 and cancelled 6,241,028 common 
shares under the NCIB. As at September 30, 2024, IPC had a total of 120,751,038 common shares issued and outstanding and 
held 30,000 common shares in treasury.
Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 40,697,533 
common shares in IPC, representing 33.7% of the outstanding common shares as at September 30, 2024.
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 3,331,566 IPC Share Unit Plan awards outstanding as at November 5, 2024 (4,333 awards granted in January 2022, 
1,090,091 awards granted in March 2022, 2,391 awards granted in July 2022, 2,072 awards granted in January 2023, 1,033,326 
awards granted in February 2023, 3,244 awards granted in July 2023, 2,443 awards granted in January 2024, 1,189,338 awards 
granted in February 2024 and 4,328 awards granted in July 2024).
Contractual Obligations and Commitments 
In the normal course of business, the Group has committed to certain payments which are not recognised as liabilities. The
following table summarizes the Group’s commitments in Canada as at September 30, 2024: 
MCAD 2024 2025 2026 2027 2028 Thereafter
Transportation service1 7.0 33.3 60.6 89.2 92.8 1,488.2
Power2 3.1 12.4 12.4 12.4 9.8 –
Total commitments 10.1 45.7 73.0 101.6 102.6 1,488.2
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2045.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from October 1, 2024 to December 
31, 2028 and an additional 5MWh at a weighted average price of CAD 58.31/MWh from October 1, 2024 to December 31, 2027.
Critical Accounting Policies and Estimates
In connection with the preparation of the Corporation’s consolidated financial statements, management has made assumptions 
and estimates about future events and applied judgments that affect the reported values of assets, liabilities, revenues, expenses 
and related disclosures. These assumptions, estimates and judgments are based on historical experience, current trends and other 
factors that they believe to be relevant at the time the financial statements are prepared. The management reviews the accounting 
policies, assumptions, estimates and judgments to ensure that the financial statements are presented fairly in accordance with 
IFRS. However, because future events and their effects cannot be determined with certainty, actual results could differ from these 
assumptions and estimates, and such differences could be material.
21

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
Transactions with Related Parties 
During the nine months ended September 30, 2024, the Group paid USD 333 thousand to the Lundin Foundation in respect of 
sustainability advisory services provided to the Group and USD 470 thousand to Orrön Energy AB in respect of office space rental. 
During the nine months ended September 30, 2024, Orrön Energy AB and ShaMaran Petroleum Corp. paid respectively USD 450 
thousand and USD 147 thousand to the Group in respect of support services provided during the first nine months of 2024.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with
parties at arm’s length.
Financial Risk Management 
As an international oil and gas exploration and production company, IPC is exposed to financial risks such as interest rate risk,
currency risk, credit risk, liquidity risks as well as the risk related to the fluctuation in oil and gas prices. The Group seeks to control 
these risks through sound management practice and the use of internationally accepted financial instruments, such as oil and gas, 
condensate and electricity price, interest rate or foreign exchange hedges as the case may be. Financial instruments will be solely 
used for the purpose of managing risks in the business. As at September 30, 2024, the Corporation had entered into oil, gas and 
electricity price hedges – see below.
Management believes that the cash resources, other current assets and cash flow from operations are sufficient to finance the
Group’s operations and capital expenditures program over the next year.
Capital Management
The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its
committed financial liabilities and work program requirements in order to create shareholder value. The Group may put in place
new bonds or credit facilities, repay debt, or pursue other such restructuring activities as appropriate.
Management of the Corporation will continuously monitor and manage the Group’s capital, liquidity and net debt position in order
to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility.
Price of Oil and Gas
Prices of oil and gas are affected by the normal economic drivers of supply and demand as well as by financial investors and 
market uncertainty. Factors that influence these prices include operational decisions, prices of competing fuels, natural disasters, 
economic conditions, transportation constraints, political instability or conflicts or actions by major oil exporting countries. Price 
fluctuations will affect the Group’s financial position. 
Based on analysis of the circumstances, management assesses the benefits of forward hedging monthly sales contracts for the 
purpose of protecting cash flow. If management believes that a hedging contract will appropriately help manage cash flow then it 
may choose to enter into a commodity price hedge. The Group does not currently have any covenants under its current financing 
facilities to hedge future production.
The Group had oil price sale financial hedges outstanding as at September 30, 2024, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
October 1, 2024 – December 31, 2024 17,700 WTI/WCS Differential USD  -15.03/bbl
October 1, 2024 – December 31, 2024 12,250 WTI Sale Swap USD 80.26/bbl
October 1, 2024 – December 31, 2024 3,000 Brent Sale Swap USD 85.50/bbl
January 1, 2025 - December 31, 2025 8,000 WTI/WCS Differential USD  -14.56/bbl
The Group had gas price sale financial hedges outstanding as at September 30, 2024, which are summarized as follows:
Period Volume (Gigajoules (GJ) per
day)) Type Average Pricing 
October 1, 2024 – December 31, 2024 15,000 AECO Swap CAD 1.515/GJ
January 1, 2025 - December 31, 2025 10,000 AECO Swap CAD 2.500/GJ
22

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
The Group had electricity financial hedges outstanding as at September 30, 2024, which are summarized as follows:
Period Volume (MWh) Type Average Pricing 
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had 
a positive fair value of USD 13,830 thousand as at September 30, 2024.
In October 2024, the Group entered into the following oil price sale financial hedges in Canada:
Period Volume (barrels per day) Type Average Pricing 
January 1, 2025 - March 31, 2025 2,500 WTI Sale Swap USD 70.00/bbl
January 1, 2025 - December 31, 2025 3,000 WTI/WCS Differential USD  -13.77/bbl
Currency Risk
The Group’s policy on currency rate hedging is, in the case of currency exposure, to consider fixing the rate of exchange. The 
Group will take into account the currency exposure, current rates of exchange and market expectations in comparison to historic 
trends and volatility in making the decision to hedge.
In 2023, IPC entered into foreign currency hedges in Canada to buy CAD 20 million per month at CAD 1.36 (sell USD) and
in Malaysia to buy MYR 11.5 million per month at MYR 4.63 (sell USD) in respect of 2024, and to buy CAD 15 million per month at
CAD 1.36 (sell USD) in respect of 2025, to partially meet forecast operational expenses in those countries. In April 2024, IPC entered
into currency hedge swaps from May 2024 to December 2024 to buy EUR 2.5 million per month, sell USD at an average exchange
rate of 1.0705. In respect of the forecast Blackrod development capital expenditure in Canada, IPC entered into further currency
hedges to purchase a total CAD 656 million for the period January 2024 to December 2025 at an average rate of CAD 1.33 (sell USD).
The outstanding portion of all of 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 3,242 thousand as at September 30, 2024.
In October 2024, in respect of the forecast operating expenditures in Canada, IPC entered into further currency hedges to purchase an 
additional CAD 90 million for the period January 2025 to December 2025 at an average rate of CAD 1.35 (sell USD). 
Interest Rate Risk
Interest rate risk is the risk to earnings due to uncertain future interest rates on borrowings. The Group will take into account the 
level of external debt, current interest rates and market expectations in comparison to historic trends and volatility in making the 
decision to hedge.
Credit Risk
The Group may be exposed to third party credit risk through contractual arrangements with counterparties who buy the Group’s 
hydrocarbon products. The Group’s policy is to limit credit risk by only entering into oil and gas sales agreements with reputable 
and creditworthy oil and gas and trading companies. Where it is determined that there is a credit risk for oil and gas sales, the 
Group’s policy is to require credit enhancement from the purchaser.
The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take 
possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In 
addition, cash is to be held and transacted only through major banks.
RISK FACTORS 
IPC is engaged in the exploration, development and production of oil and gas and is exposed to various operational, environmental, 
market and financial risks and uncertainties. For further information and discussion of these risks and uncertainties, please see 
IPC’s Annual Information Form for the year ended December 31, 2023 (”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” in this MD&A.
23

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be 
disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation 
is recorded, processed, summarized and reported within the time periods specified in the securities legislation. Management, 
under the supervision of the Chief Executive Officer and the Chief Financial Officer, is responsible for the design and operation of 
disclosure controls and procedures.
Internal Controls over Financial Reporting
Management is also responsible for the design of the Group’s internal controls over financial reporting in order to provide reasonable 
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in 
accordance with IFRS. However, due to inherent limitations, internal control over financial reporting may not prevent or detect all 
misstatements and fraud. 
There have been no material changes to the Groups internal control over financial reporting during the nine months period ended 
September 30, 2024, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over 
financial reporting. 
Control Framework 
Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control 
– Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission 
(COSO).   
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 
This MD&A contains statements and information which constitute “forward-looking statements“ or “forward-looking information“ 
(within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements“) 
relate to future events, including the Corporation’s future performance, business prospects or opportunities. Actual results may differ 
materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this MD&A 
are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this MD&A, unless 
otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except 
as required by applicable laws. 
All statements other than statements of historical fact may be forward-looking statements. Any statements that express or involve 
discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, guidance, budgets, objectives, assumptions 
or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“, “continue“, 
“estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, “might“, “should“, 
“believe“, “budget“ and similar expressions) are not statements of historical fact and may be “forward-looking statements“. 
Forward-looking statements include, but are not limited to, statements with respect to: 
• 2024 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 continue to react to recent events and navigate the Corporation through periods of 
volatile commodity prices; 
• The ability to fully fund future expenditures from cash flows and current borrowing capacity; 
• IPC’s intention and ability to continue to implement strategies to build long-term shareholder value; 
• The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth; 
• The continued facility uptime and reservoir performance in IPC’s areas of operation; 
• Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing, 
regulatory approvals, third party commercial arrangements, breakeven oil prices and net present values;
• Current and future production performance, operations and development potential of the Onion Lake Thermal, Suffield, 
Brooks, Ferguson and Mooney 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 to maintain current and forecast production in France and Malaysia; 
• The intention and ability of IPC to acquire further common shares under the NCIB, including the timing of any such purchases;
• The ability of IPC to renew the NCIB and the number of common shares which may be purchased under a renewed NCIB;
• The return of value to IPC’s shareholders as a result of the NCIB;
• The ability of IPC to implement further shareholder distributions in addition to the NCIB;
• IPC’s ability to implement its 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 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;
24

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
• IPC’s ability to maintain operations, production and business in light of any future pandemics and the restrictions and 
disruptions related thereto, including risks related to production delays and interruptions, changes in laws and regulations and 
reliance on third party operators and infrastructure; 
• IPC’s ability to identify and complete future acquisitions;
• Expectations regarding the oil and gas industry in Canada, Malaysia and France, including assumptions regarding future 
royalty rates, regulatory approvals, legislative changes, 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: 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; our ability to maintain 
our existing credit ratings; our ability to achieve our 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 we will be able to implement our 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; our intention to complete share repurchases 
under our normal course issuer bid program, including the funding of such share repurchases, existing and future market 
conditions, including with respect to the price of our 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.
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 our systems, including our 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 the war between Ukraine and Russia and the conflict in the Middle East, and their potential 
impact on, among other things, global market conditions; 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”
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, 2023, (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).
25

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
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 are effective as of December 31, 2023, and are included in the reports prepared by Sproule Associates Limited (Sproule), 
an independent qualified reserves evaluator, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and 
Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule’s December 
31, 2023 price forecasts. 
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in 
France and Malaysia are effective as of December 31, 2023, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), 
an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 
31, 2023 price forecasts. 
The price forecasts used in the Sproule and ERCE reports, are available on the website of Sproule (sproule. com) and are contained 
in the AIF . These price forecasts are as at December 31, 2023 and may not be reflective of current and future forecast commodity 
prices.
The reserve life index (RLI) is calculated by dividing the 2P reserves of 468 MMboe as at December 31, 2023, by the mid-point of 
the 2024 CMD production guidance of 46,000 to 48,000 boepd.
The product types comprising the 2P reserves 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.
“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.
26

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
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.
2P reserves and contingent resources included in the reports prepared by Sproule and ERCE have been aggregated by IPC. 
Estimates of reserves, resources and future net revenue for individual properties may not reflect the same level of confidence 
as estimates of reserves, resources and future net revenue for all properties, due to aggregation. This MD&A contains estimates 
of the net present value of the future net revenue from IPC’s reserves and contingent resources. The estimated values of future 
net revenue disclosed in this MD&A do not represent fair market value. There is no assurance that the forecast prices and cost 
assumptions used in the reserve and resources evaluations will be attained and variances could be material.
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.  
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel 
(bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value 
equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and 
crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an 
indication of value.
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, 2024 21.9 7.8 91.9 MMcf                     
(15.3 Mboe) 45.0
September 30, 2023 25.8 7.1 103.4 MMcf                     
(17.3 Mboe) 50.2
Nine months ended
September 30, 2024 23.7 7.9 94.8 MMcf
(15.8 Mboe) 47.4
September 30, 2023 25.9 8.6 102.4 MMcf
(17.1 Mboe) 51.6
Year ended December 31, 2023
December 31, 2023 25.8 8.1 102.8MMcf                     
(17.1 Mboe) 51.1
This MD&A also makes reference to IPC’s forecast total average daily production of 46,000 to 48,000 boepd for 2024. IPC 
estimates that approximately 50% of that production will be comprised of heavy oil, approximately 16% will be comprised of light 
and medium crude oil and approximately 34% will be comprised of conventional natural gas.
27

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
OTHER SUPPLEMENTARY INFORMATION
Abbreviations
CAD  Canadian dollar
MCAD  Million Canadian dollar
EUR  Euro
USD  US dollar
MUSD  Million US dollar
MYR  Malaysian Ringgit
FPSO  Floating Production Storage and Offloading (facility)
OECD  Organisation for Economic Co-operation and Development
Oil related terms and measurements
AECO   The daily average benchmark price for natural gas at the AECO hub in southeast Alberta                                                                            
AESO  Alberta Electric System Operator
API   An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale
ASP   Alkaline surfactant polymer (an EOR process)
bbl   Barrel (1 barrel = 159 litres)
boe1   Barrels of oil equivalents
boepd   Barrels of oil equivalents per day
bopd   Barrels of oil per day
Bcf  Billion cubic feet
Bscf   Billion standard cubic feet 
C5  Condensate
CO2e  Carbon dioxide equivalents, including carbon dioxide, methane and nitrous oxide
Empress   The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border
EOR   Enhanced Oil Recovery
GJ  Gigajoules
Mbbl   Thousand barrels
MMbbl   Million barrels
Mboe   Thousand barrels of oil equivalents 
Mboepd   Thousand barrels of oil equivalents per day
Mbopd   Thousand barrels of oil per day
MMboe   Million barrels of oil equivalents
MMbtu   Million British thermal units
Mcf   Thousand cubic feet
Mcfpd  Thousand cubic feet per day
MMcf   Million cubic feet
MW  Mega watt
MWh  Mega watt per hour
NGL   Natural gas liquid
SAGD   Steam assisted gravity drainage (a thermal recovery process)
WTI   West Texas Intermediate (a light oil reference price)
WCS   Western Canadian Select (a heavy oil reference price)
1  All volume references to boe are calculated on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) 
unless otherwise indicated. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and 
does not represent a value equivalency at the wellhead. BOEs may be misleading, particularly if used in isolation. Given that the value ratio based 
on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 
6:1 basis may be misleading as an indication of value.
28

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

Management’s Discussion and Analysis
For the three and nine months ended September 30, 2024
DIRECTORS
C. Ashley Heppenstall
Director, Chair
London, England
William Lundin
Director, President and Chief Executive Officer
Coppet, Switzerland
Chris Bruijnzeels
Director
Abcoude, The Netherlands
Donald K. Charter
Director
Toronto, Ontario, Canada
Lukas (Harry) H. Lundin
Director
Toronto, Ontario, Canada
Emily Moore
Director
Toronto, Ontario, Canada
Mike Nicholson
Director
Monaco
Deborah Starkman
Director
Toronto, Ontario, Canada
OFFICERS
Christophe Nerguararian
Chief Financial Officer
Geneva, Switzerland
Nicki Duncan
Chief Operating Officer
Geneva, Switzerland
Jeffrey Fountain
General Counsel and Corporate Secretary
Geneva, Switzerland
Rebecca Gordon
Senior Vice President Corporate Planning and 
Investor Relations
Geneva, Switzerland 
Chris Hogue
Senior Vice President, Canada
Calgary, Alberta, Canada
Ryan Adair
Vice President Asset Management and
Corporate Planning, Canada
Calgary, Alberta, Canada
Curtis White
Vice President Commercial, Canada
Calgary, Alberta, Canada
MEDIA AND INVESTOR RELATIONS
Robert Eriksson 
Stockholm, Sweden
CORPORATE OFFICE
Suite 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

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

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