Kvartalsrapport Q2 2025

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

Q2
International Petroleum Corporation
Interim Condensed Consolidated 
Financial Statements
For the three and six months ended June 30, 2025

===== SIDA 2 =====

2
Contents
Interim Condensed Consolidated Statement of Operations  3
Interim Condensed Consolidated Statement of Comprehensive Income  4
Interim Condensed Consolidated Balance Sheet  5
Interim Condensed Consolidated Statement of Cash Flow 6
Interim Condensed Consolidated Statement of Changes in Equity 7
Notes to the Interim Condensed Consolidated Financial Statements 8
Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

===== SIDA 3 =====

3
Interim Condensed Consolidated Statement of Operations
For the three and six months ended June 30, 2025 and 2024, UNAUDITED
Three months ended June 30 Six months ended June 30
USD Thousands Note 2025 2024 2025 2024
Revenue 2 158,892 219,040 337,384 425,459
Cost of sales
Production costs 3 (103,910) (111,381) (207,289) (227,126)
Depletion and decommissioning costs 8 (29,321) (32,661) (58,337) (65,814)
Depreciation of other tangible fixed assets 8 (1,461) (2,218) (3,378) (4,480)
Exploration and business development costs (537) (72) (568) (147)
Gross profit 2 23,663 72,708 67,812 127,892
Other income/(expenses) 238 – 523 –
General, administration and depreciation expenses (4,043) (3,980) (8,712) (7,929)
Profit before financial items 19,858 68,728 59,623 119,963 
Finance income 4 14,909 4,917 16,561 10,534 
Finance costs 5 (14,750) (14,965) (35,257) (30,352)
Net financial items 159 (10,048) (18,696) (19,818)
Profit before tax 20,017 58,680 40,927 100,145
Income tax expense 6 (6,167) (13,470) (10,846) (21,216)
Net result 13,850 45,210 30,081 78,929 
Net result attributable to:
Shareholders of the Parent Company 13,848 45,202 30,077 78,914 
Non-controlling interest 2 8 4 15 
13,850 45,210 30,081 78,929 
Earnings per share – USD1 14 0.12 0.36 0.26 0.63
Earnings per share fully diluted – USD1 14 0.12 0.36 0.25 0.62
1  Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the interim condensed consolidated financial statements

===== SIDA 4 =====

4
Interim Condensed Consolidated Statement of Comprehensive Income
For the three and six months ended June 30, 2025 and 2024, UNAUDITED
Three months ended June 30 Six months ended June 30
USD Thousands Note 2025 2024 2025 2024
Net result 13,850 45,210 30,081 78,929
Other comprehensive income/(loss)
Items that may be reclassified to profit or loss:
Reclassification of hedging (gains)/losses to profit or 
loss 2 (4,715) 2,644 3,359 (6,562)
(Loss)/Gain on cash flow hedges 42,786 10,653 37,649 (34,766)
Income tax relating to these items (9,068) (3,070) (9,770) 9,933
Currency translation adjustments 49,095 (8,839) 53,041 (31,211)
Total comprehensive income 91,948 46,598 114,360 16,323
Total comprehensive income attributable to:
Shareholders of the Parent Company 91,944 46,600 114,351 16,323
Non-controlling interest 4 (2) 9 –
91,948 46,598 114,360 16,323
See accompanying notes to the interim condensed consolidated financial statements

===== SIDA 5 =====

5
Interim Condensed Consolidated Balance Sheet
As at June 30, 2025 and December 31 2024, UNAUDITED
USD Thousands Note June 30, 2025 December 31, 2024
ASSETS
Non-current assets
Exploration and evaluation assets 7 3,967 480
Property, Plant and Equipment 8 1,719,182 1,500,912
Right-of-use assets 3,645 3,103
Deferred tax assets 6 1,134 1,673
Derivative instruments 18 1,006 –
Other non-current assets 9 52,037 48,665
Total non-current assets 1,780,971 1,554,833
Current assets
Inventories 10 26,922 20,073
Trade and other receivables 11 111,756 127,450
Derivative instruments 18 23,024 3,219
Current tax receivables 2,317 1,514
Cash and cash equivalents 12 78,886 246,593
Total current assets 242,905 398,849
TOTAL ASSETS 2,023,876 1,953,682
LIABILITIES
Non-current liabilities
Financial liabilities 15 – 1,719
Bonds 15 442,262 439,862
Lease liabilities 3,090 2,728
Provisions 16 290,232 268,509
Deferred tax liabilities 6 119,191 92,754
Derivative instruments 18 – 562
Total non-current liabilities 854,775 806,134
Current liabilities
Trade and other payables 17 195,207 176,371
Financial liabilities 18 3,863 3,402
Derivative instruments 18 – 19,869
Current tax liabilities 497 1,146
Lease liabilities 882 573
Provisions 16 6,037 6,717
Total current liabilities 206,486 208,078
EQUITY
Shareholders’ equity 962,467 939,315
Non-controlling interest 148 155
Net shareholders’ equity 962,615 939,470
TOTAL EQUITY AND LIABILITIES 2,023,876 1,953,682
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

===== SIDA 6 =====

6
Interim Condensed Consolidated Statement of Cash Flow
For the three and six months ended June 30, 2025 and 2024, UNAUDITED
Three months ended June 30 Six months ended June 30
USD Thousands Note 2025 2024 2025 2024
Cash flow from operating activities
Net result 13,850 45,210 30,081 78,929
Depletion, depreciation and amortization 2, 8 31,134 35,171 62,378 70,881 
Income tax 6 6,167 13,470 10,846 21,216
Amortization of capitalized financing fees 5 529 500 1,048 1,010
Foreign currency exchange loss/(gain) 4, 5 (14,215) 1,556 (14,233) 3,617 
Interest income 4 (694) (4,917) (2,328) (10,534)
Interest expense 5 8,980 8,928 17,741 17,746
Unwinding of asset retirement obligation discount 4,115 3,641 8,072 7,259
Share-based costs 2,448 2,242 4,709 4,176
Changes in working capital 20,619 (22,067) 18,330 (71,027)
Decommissioning costs paid 16 (2,097) (2,241) (2,418) (2,363)
Other payments 16 (125) – (828) (504)
Net income taxes paid 46 3,742 (2,088) 277
Interests received 492 3,268 2,634 8,279
Interests paid (55) (48) (16,406) (16,414)
Other 1,806 130 2,051 316
Net cash flow from operating activities 73,000 88,585 119,589 112,864
Cash flow used in investing activities
Investment in oil gas properties 8 (97,925) (84,175) (196,811) (209,486)
Investment in other tangible fixed assets 8 (193) – (221) –
Net cash (outflow) from investing activities (98,118) (84,175) (197,032) (209,486)
Cash flow from financing activities
Repayments 15 (497) (945) (1,169) (2,014)
Paid financing fees (686) – (686) –
Repurchase of own shares (“NCIB”) 13 (25,517) (28,430) (78,704) (45,738)
Other payments (246) (249) (464) (472)
Dividend paid (16) – (16) –
Net cash (outflow) from financing activities (26,962) (29,624) (81,039) (48,224)
Change in cash and cash equivalents (52,080) (25,214) (158,482) (144,846)
Cash and cash equivalents at the beginning of the 
period 140,194 397,390 246,593 517,074
Currency exchange difference in cash and cash 
equivalents (9,228) (3,379) (9,225) (3,431)
Cash and cash equivalents at the end of the period 78,886 368,797 78,886 368,797
   
See accompanying notes to the interim condensed consolidated financial statements

===== SIDA 7 =====

7
Interim Condensed Consolidated Statement of Changes in Equity
For the three and six months ended June 30, 2025 and 2024, 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, 2025 141,173 875,952 (81,192) 18,092 (13,138) (1,572) 939,315 155 939,470
Net result –  30,077    – – – –  30,077    4  30,081    
Cash flow hedges – – – –  31,238    –  31,238    –  31,238    
Currency translation difference – –  52,002     800     234    –      53,036     5     53,041    
Total comprehensive income –  30,077     52,002     800     31,472    –      114,351     9     114,360    
Repurchase of own shares 
(NCIB)1 (78,704) –  –      –     –      – (78,704) – (78,704)
Dividend Distribution – – – – – – – (16) (16)
Share based costs – – –  4,709    –    –     4,709 – 4,709 
Share based payments2 – (8,198) –     (9,006) –      –     (17,204) – (17,204)
Balance at June 30, 2025 62,469 897,831 (29,190) 14,595 18,334 (1,572) 962,467 148 962,615 
1  See Note 13
2 The third instalment of IPC RSP 2022 awards, the second instalment of IPC RSP 2023 awards, the first instalment of IPC RSP 2024 awards and 
the IPC PSP 2022 awards vested on February 1, 2025, at a price of CAD 18.89 per award. The difference between the value at vesting date and 
at grant (respectively CAD 9.09 per award, CAD 14.24 per award, CAD 14.82 per award and CAD 8.40 per award) was offset against retained 
earnings. 
USD Thousands
Share 
capital and 
premium
Retained 
earnings CTA IFRS 2 
reserve
MTM 
reserve
Pension 
reserve Total
Non-
controlling 
interest
Total
equity
Balance at January 1, 2024 243,361 795,490 (10,745) 18,838 31,344 1,786 1,080,074 185 1,080,259
Net result – 78,914 – – – – 78,914 15 78,929
Cash flow hedges – – – – (31,395) – (31,395) – (31,395)
Currency translation difference – – (28,227) (2,221) (748) – (31,196) (15) (31,211)
Total comprehensive income – 78,914 (28,227) (2,221) (32,143) – 16,323 – 16,323
Repurchase of own shares 
(NCIB)1 (46,627) – – – – – (46,627) – (46,627)
Dividend distribution – – – – – – – (41) (41)
Share based costs – – – 4,176 – – 4,176 – 4,176
Share based payments2                     – (21,740) – (6,131) – – (27,871) – (27,871)
Balance at June 30, 2024 196,734 852,664 (38,972) 14,662 (799) 1,786 1,026,075 144 1,026,219
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 February 1, 2024, at a price of CAD 14.90 per award. The difference between the value at vesting date and 
at grant (respectively CAD 4.07 per award, CAD 9.09 per award, CAD 14.27 per award and CAD 3.61 per award) was offset against retained 
earnings. 
See accompanying notes to the interim condensed consolidated financial statements

===== SIDA 8 =====

8
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED
1. CORPORATE INFORMATION AND MATERIAL ACCOUNTING POLICIES
A. The Group
International Petroleum Corporation (“IPC” or the “Corporation” and, together with its subsidiaries, the “Group”) is in the business 
of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development 
projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange (“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 IFRS Accounting 
Standards applicable to the preparation of interim financial statements, under International Accounting Standard 34, Interim 
Financial Reporting (together “IFRS Accounting Standards“). The unaudited interim condensed consolidated financial statements 
should be read in conjunction with IPC’s annual audited consolidated financial statements for the year ended December 31, 2024, 
which have been prepared in accordance with IFRS Accounting standards as issued by the IASB.
These unaudited interim condensed consolidated financial statements are presented in United States Dollars (USD), which is 
the Group’s presentation and functional currency. The unaudited interim condensed consolidated financial statements have been 
prepared on a historical cost basis, except for items that are required to be accounted for at fair value as detailed in the Group’s 
accounting policies. Intercompany transactions and balances have been eliminated. 
The unaudited interim condensed consolidated financial statements have been approved by the Board of Directors of IPC and 
authorized for issuance on August 5, 2025.
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, 2024.
C. Change in presentation
Certain comparative figures have been reclassified to conform with the financial statements presentation in the current year.
D. Going concern
The Group’s unaudited interim condensed consolidated financial statements for the three and six months period ended June 30, 
2025, 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 six months ended June 30, 2025, the Group applied the amended accounting standards, interpretations and annual 
improvement points that are effective as of January 1, 2025. 
F. Future accounting changes 
On April 9, 2024, the International Accounting Standards Boards issued IFRS 18 Presentation and Disclosure in Financial
Statements (”IFRS 18”), which aims to improve how companies communicate their financial statements, with a focus on
information about financial performance in the statement of profit or loss. IFRS 18 is effective January 1, 2027. The Corporation is 
in the process of assessing the impact that the standard will have on its financial statements.
On May 30, 2024, the International Accounting Standards Board issued amendments to IFRS 9 Financial Instruments and IFRS 7
Financial Instruments: Disclosures, which aim to improve the classification and measurement of financial instruments, including
clarifications on contractual cash flow characteristics and environmental, social and governance-related features. The
amendments are effective for annual reporting periods beginning on or after January 1, 2026, with early application permitted. The
Corporation is in the process of assessing the impact that these amendments will have on its financial statements.

===== SIDA 9 =====

9
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, 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 June 30, 2025
USD Thousands Canada Malaysia France Other Total
Crude oil 140,002 11,828 11,463 – 163,293
NGLs 167 – – – 167
Gas 9,752 – – – 9,752
Net sales of oil and gas 149,921 11,828 11,463 – 173,212
Change in under/over lift position – – 1,559 – 1,559
Royalties (20,885) – (732) – (21,617)
Hedging settlement 5,375 – – – 5,375
Other operating revenue – – 205 158 363
Revenue 134,411 11,828 12,495 158 158,892
Operating costs (50,286) (11,768) (8,468) – (70,522)
Cost of blending (33,269) – – – (33,269)
Change in inventory position (315) 203 (7) – (119)
Depletion and decommissioning costs (21,537) (4,891) (2,893) – (29,321)
Depreciation of other tangible fixed assets – (1,461) – – (1,461)
Exploration and business development costs – – – (537) (537)
Gross profit/(loss) 29,004 (6,089) 1,127 (379) 23,663
Three months ended June 30, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 191,018 39,341 17,253 – 247,612
NGLs 275 – – – 275
Gas 6,675 – – – 6,675
Net sales of oil and gas 197,968 39,341 17,253 – 254,562
Change in under/over lift position – – 2,215 – 2,215
Royalties (34,289) – (1,161) – (35,450)
Hedging settlement (2,644) – – – (2,644)
Other operating revenue – – 237 120 357
Revenue 161,035 39,341 18,544 120 219,040
Operating costs (49,801) (7,229) (7,804) – (64,834)
Cost of blending (41,675) – – – (41,675)
Change in inventory position (96) (4,829) 53 – (4,872)
Depletion and decommissioning costs (22,486) (6,893) (3,282) – (32,661)
Depreciation of other tangible fixed assets – (2,218) – – (2,218)
Exploration and business development costs – – – (72) (72)
Gross profit/(loss) 46,977 18,172 7,511 48 72,708

===== SIDA 10 =====

10
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED
Six months ended June 30, 2025
USD Thousands Canada Malaysia France Other Total
Crude oil 302,024 27,204 24,277 – 353,505
NGLs 358 – – – 358
Gas 21,374 – – – 21,374
Net sales of oil and gas 323,756 27,204 24,277 – 375,237
Change in under/over lift position – – 2,700 – 2,700
Royalties (43,673) – (1,572) – (45,245)
Hedging settlement 4,159 – – – 4,159
Other operating revenue – – 375 158 533
Revenue 284,242 27,204 25,780 158 337,384
Operating costs (102,791) (20,349) (16,535) – (139,675)
Cost of blending (70,995) – – – (70,995)
Change in inventory position 13 3,542 (174) – 3,381
Depletion and decommissioning costs (42,636) (10,642) (5,059) – (58,337)
Depreciation of other tangible fixed assets – (3,378) – – (3,378)
Exploration and business development costs – – – (568) (568)
Gross profit/(loss) 67,833 (3,623) 4,012 (410) 67,812
Six months ended June 30, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 360,634 57,894 33,970 – 452,498
NGLs 519 – – – 519
Gas 21,092 – – – 21,092
Net sales of oil and gas 382,245 57,894 33,970 – 474,109
Change in under/over lift position – – 5,131 – 5,131
Royalties (58,772) – (2,300) – (61,072)
Hedging settlement 6,562 – – – 6,562
Other operating revenue – – 454 275 729
Revenue 330,035 57,894 37,255 275 425,459
Operating costs (109,690) (14,245) (16,715) – (140,650)
Cost of blending (86,881) – – – (86,881)
Change in inventory position 43 210 152 – 405
Depletion and decommissioning costs (45,390) (13,923) (6,501) – (65,814)
Depreciation of other tangible fixed assets – (4,480) – – (4,480)
Exploration and business development costs – – – (147) (147)
Gross profit/(loss) 88,117 25,456 14,191 128 127,892

===== SIDA 11 =====

11
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED
3. PRODUCTION COSTS
Three months ended June 30 Six months ended June 30
USD Thousands 2025 2024 2025 2024
Cost of operations 60,915 54,183 119,117 119,196 
Tariff and transportation expenses 8,505 9,387 18,449 18,930 
Direct production taxes 1,102 1,264 2,109 2,524 
Operating costs 70,522 64,834 139,675 140,650 
Cost of blending1 33,269 41,675 70,995 86,881 
Change in inventory position 119 4,872 (3,381) (405)
Total production costs 103,910 111,381 207,289 227,126 
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 June 30 Six months ended June 30
USD Thousands 2025 2024 2025 2024
Foreign exchange gain, net 14,215 – 14,233 –
Interest income 694 4,917 2,328 10,534
Total finance income 14,909 4,917 16,561 10,534
5. FINANCE COSTS
Three months ended June 30 Six months ended June 30
USD Thousands 2025 2024 2025 2024
Foreign exchange loss, net – 1,556 – 3,617
Interest expense 8,980 8,928 17,741 17,746
Unwinding of asset retirement obligation discount 4,115 3,641 8,072 7,259 
Amortization of capitalized financing fees 529 500 1,048 1,010 
Loan commitment fees 314 223 544 445 
Currency hedge losses, net 660 – 7,518 – 
Other financial costs 152 117 334 275 
Total finance costs 14,750 14,965 35,257 30,352 
6. INCOME TAX
Three months ended June 30 Six months ended June 30
USD Thousands 2025 2024 2025 2024
Current tax (337) (5,718) (851) (7,091)
Deferred tax (5,830) (7,752) (9,995) (14,125)
Total tax expense (6,167) (13,470) (10,846) (21,216)
The Group is within the scope of the OECD Pillar Two model rules. The Group applies the exception to recognising and disclosing 
information about deferred tax assets and liabilities related to Pillar Two income taxes.

===== SIDA 12 =====

12
Specification of deferred tax assets and tax liabilities1
USD Thousands June 30, 2025 December 31, 2024
Unused tax loss carry forward  50,961  40,042 
Derivative hedges 234  3,933 
Other 5,221  10,302
Deferred tax assets 56,416 54,277
Accelerated allowances  168,775  145,358
Derivative hedges 5,698 –
Deferred tax liabilities 174,473 145,358
Deferred taxes, net (118,057)  (91,081)
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, 2025 480 – – 480
Additions 3,399 – – 3,399
Currency translation adjustments 88 – – 88
Net book value June 30, 2025 3,967 – – 3,967
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 – – – –
Additions 500 1,407 12 1,919
Write-off – (1,407) (12) (1,419)
Currency translation adjustments (20) – – (20)
Net book value December 31, 2024 480 – – 480
8. PROPERTY, PLANT AND EQUIPMENT
USD Thousands 2025 2024
Oil and gas properties                 1,705,940    1,484,487
Other tangible fixed assets  13,242    16,425
Property, Plant and Equipment  1,719,182 1,500,912
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

===== SIDA 13 =====

13
Oil and gas properties
USD Thousands Canada Malaysia France Total
Cost
January 1, 2025 1,767,580 599,734 405,129 2,772,443
Additions 164,727 24,652 4,033 193,412
Change in estimates 1,230 – – 1,230
Currency translation adjustments 97,429 – 51,675 149,104
June 30, 2025 2,030,966 624,386 460,837 3,116,189
Accumulated depletion
January 1, 2025 (451,017) (530,315) (306,624) (1,287,956)
Depletion charge for the period (42,636) (10,642) (5,059) (58,337)
Currency translation adjustments (24,832) – (39,124) (63,956)
June 30, 2025 (518,485) (540,957) (350,807) (1,410,249)
Net book value June 30, 2025 1,512,481 83,429 110,030 1,705,940
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 1,465,010 591,123 436,693 2,492,826
Additions 412,284 17,035 3,475 432,794
Disposals (94) – – (94)
Change in estimates 36,995 (8,424) (9,018) 19,553
Reclassifications (10,773) – – (10,773)
Currency translation adjustments (135,842) – (26,021) (161,863)
December 31, 2024 1,767,580 599,734 405,129 2,772,443
Accumulated depletion
January 1, 2024 (398,288) (502,834) (313,282) (1,214,404)
Depletion charge for the year (88,583) (27,481) (12,328) (128,392)
Disposals 94 – – 94
Currency translation adjustments 35,760 – 18,986 54,746
December 31, 2024 (451,017) (530,315) (306,624) (1,287,956)
Net book value December 31, 2024 1,316,563 69,419 98,505 1,484,487
                                    
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

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

14
Other tangible fixed assets
USD Thousands FPSO Other Total
Cost
January 1, 2025 204,853 9,824 214,677
Additions – 221 221
Disposals – (6) (6)
Currency translation adjustments – 792 792
June 30, 2025 204,853 10,831 215,684
Accumulated depreciation
January 1, 2025 (190,056) (8,196) (198,252)
Depreciation charge for the period (3,378) (166) (3,544)
Disposals – 6 6
Currency translation adjustments – (652) (652)
June 30, 2025 (193,434) (9,008) (202,442)
Net book value June 30, 2025 11,419 1,823 13,242
USD Thousands FPSO Other Total
Cost
January 1, 2024 204,853 10,048 214,901
Additions – 363 363
Currency translation adjustments – (587) (587)
December 31, 2024 204,853 9,824 214,677
Accumulated depreciation
January 1, 2024 (181,123) (8,340) (189,463)
Depreciation charge for the year (8,933) (334) (9,267)
Currency translation adjustments – 478 478
December 31, 2024 (190,056) (8,196) (198,252)
Net book value December 31, 2024 14,797 1,628 16,425
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 six months ended June 30, 2025 and 2024, UNAUDITED

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

15
9. OTHER NON-CURRENT ASSETS
USD Thousands June 30, 2025 December 31, 2024
Financial assets  37,282     34,788  
Intangible assets  14,755     13,877    
 52,037     48,665       
Financial assets mainly represent cash payments made in local currency to an asset retirement obligation fund for the Bertam 
field, Malaysia for an amount equivalent of USD 33.3 million (2024: USD 30.6 million). Financial assets also include cash-
collateralized guarantees placed in 2023 in respect of work commitments in Malaysia amounting to USD 4.0 million. 
Intangible assets mainly represent carbon offsets purchased in Canada. 
10. INVENTORIES
USD Thousands June 30, 2025 December 31, 2024
Hydrocarbon stocks 15,455  11,250    
Well supplies and operational spares 11,467  8,823    
26,922  20,073    
11. TRADE AND OTHER RECEIVABLES
USD Thousands June 30, 2025 December 31, 2024
Trade receivables  75,708    94,265    
Underlift  4,031    1,007       
Joint operations debtors  2,648    1,432    
Prepaid expenses and accrued income  19,103    12,346
Other  10,266    18,400 
 111,756    127,450    
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, 2024 126,992,066
Cancellation of repurchased common shares (NCIB) (7,822,595)
Balance at December 31, 2024 119,169,471
Cancellation of repurchased common shares (NCIB) (5,814,939)
Balance at June 30, 2025 113,354,532
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. The 
Corporation is authorized to issue an unlimited number of Common Shares without par value.
As at January 1, 2024, IPC had a total of 126,992,066 common shares issued and outstanding, with no common shares held in 
treasury.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

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

16
During 2024, under the normal course issuer bid (NCIB) announced in December 2023 and renewed in December 2024, IPC 
purchased and cancelled an aggregate of 7,822,595 common shares.
As at December 31, 2024, IPC had a total of 119,169,471 common shares issued and outstanding, and held 110,156 common 
shares in treasury.
During the first six month of 2025, IPC purchased 5,492,965 common shares under the NCIB and 211,818 common shares under 
certain other exemptions in Canada. All of these purchased common shares, including the common shares held in treasury as at 
December 31, 2024, were cancelled during the first six month of 2025.
As at June 30, 2025, IPC had a total of 113,354,532 common shares issued and outstanding, with no common shares held in 
treasury.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares.
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 years presented.
Three months ended June 30 Six months ended June 30
2025 2024 2025 2024
Net result attributable to shareholders of the Parent Company, USD 13,848,567 45,201,621 30,077,554 78,913,683
Weighted average number of shares for the period 115,156,270  125,414,090 117,207,237  126,216,022 
Earnings per share, USD  0.12  0.36 0.26  0.63 
Weighted average diluted number of shares for the period  116,613,413  127,026,090  118,664,380  127,828,022 
Earnings per share fully diluted, USD 0.12  0.36 0.25  0.62 
15. FINANCIAL LIABILITIES
USD Thousands June 30, 2025 December 31, 2024
Current bank loans  3,863    3,402
Non current bank loans – 1,719
Bonds  444,956    443,407
Capitalized financing fees (2,694) (3,545) 
 446,125    444,983
As at June 30, 2025, IPC had USD 450 million of bonds outstanding, maturing in February 2027 with a fixed coupon rate of 7.25% 
per annum, payable in semi-annual instalments in August and February.
Of the USD 450 million of bonds outstanding, USD 150 million of bonds were 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.
The bond repayment obligations as at June 30, 2025, are classified as non-current as there are no mandatory repayments within 
the next twelve months.
In addition, as at June 30, 2025, the Group had a revolving credit facility of CAD 250 million (the “Canadian RCF”) in connection 
with its oil and gas assets in Canada. During Q2 2025, the Group increased the Canadian RCF from CAD 180 million to CAD 250 
million and extended the maturity date. The Canadian RCF has a maturity in May 2027 and was undrawn and fully available as 
at June 30, 2025. During 2024, the Group entered into a letter of credit facility in Canada (the “LC Facility”) to cover existing 
operational letters of credit. As at June 30, 2025, operational letters of credit in an aggregate of CAD 40.2 million have been issued 
under the LC Facility, including letters of credit of CAD 35 million to support the third party pipeline construction agreements for 
the Blackrod project which are expected to be released when these pipelines become operational.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

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

17
As at June 30, 2025, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May
2026. IPC makes quarterly repayments of the France Facility and the amount remaining outstanding under the France Facility as at 
June 30, 2025 was USD 3.9 million (EUR 3.3 million) which 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 June 30, 2025.
16. PROVISIONS
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2025 267,790 1,679 3,685 2,072 275,226
Additions – – – 523 523
Unwinding of asset retirement obligation discount 8,072 – – – 8,072
Payments (2,418) – – (828) (3,246)
Change in estimates 1,230 – – – 1,230
estimates 764 – – – 764
Currency translation adjustments 13,491 103 – 106 13,700
June 30, 2025 288,929 1,782 3,685 1,873 296,269
Non-current 284,079 595 3,685 1,873 290,232
Current 4,850 1,187 – – 6,037
Total 288,929 1,782 3,685 1,873 296,269
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2024 253,949 2,176 551 2,078 258,754
Additions – – 682 544 1,226
Disposals (197) – – – (197)
Unwinding of asset retirement obligation discount 14,568 – – – 14,568
Payments (7,711) (591) (906) (500) (9,708)
Change in estimates 19,553 – 3,491 – 23,044
Reclassification1 1,013 – – – 1,013
Currency translation adjustments (13,385) 94 (133) (50) (13,474)
December 31, 2024 267,790 1,679 3,685 2,072 275,226
Non-current 261,632 1,120 3,685 2,072 268,509
Current 6,158 559 – – 6,717
Total 267,790 1,679 3,685 2,072 275,226
1 The reclassification of the asset retirement obligation related to the 2024 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 9). 
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% (2024: 6%) per annum was used, 
based on a credit risk adjusted rate.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

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18
17. TRADE AND OTHER PAYABLES
USD Thousands June 30, 2025 December 31, 2024
Trade payables  37,324     42,634    
Joint operations creditors  30,671     11,671    
Accrued expenses  120,554     119,316    
Other  6,658     2,750    
 195,207     176,371    
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:
June 30, 2025
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 37,282 37,282 – –
Derivative instruments 24,030 – – 24,030
Joint operation debtors 2,648 2,648 – –
Other current receivables2 92,322 88,291 4,031 –
Cash and cash equivalents 78,886 78,886 – –
Financial assets 235,168 207,107 4,031 24,030
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
June 30, 2025
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 442,262 442,262 – –
Current financial liabilities 3,863 3,863 – –
Joint operation creditors 30,671 30,671 – –
Other current liabilities 165,033 165,033 – –
Financial liabilities 641,829 641,829 – –
December 31, 2024
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 34,788 34,788 – –
Derivative instruments 3,219 – – 3,219
Joint operation debtors 1,432 1,432 – –
Other current receivables2 115,186 114,179 1,007 –
Cash and cash equivalents 246,593 246,593 – –
Financial assets 401,218 396,992 1,007 3,219
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

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

19
December 31, 2024
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 441,581 441,581 – –
Current financial liabilities 3,402 3,402 – –
Derivative instruments 20,431 – – 20,431
Joint operation creditors 11,671 11,671 – –
Other current liabilities 165,846 165,846 – –
Financial liabilities 642,931 622,500 – 20,431
The 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:
June 30, 2025
USD Thousands Level 1 Level 2 Level 3
Other current receivables 4,031 – –
Derivative instruments – current – 23,024 –
Derivative instruments – non-current – – 1,006
Financial assets 4,031 23,024 1,006
Derivative instruments – current – – –
Derivative instruments – non-current – – –
Financial liabilities – – –
December 31, 2024
USD Thousands Level 1 Level 2 Level 3
Other current receivables 1,007 – –
Derivative instruments – current – 3,219 –
Derivative instruments – non-current – – –
Financial assets 1,007 3,219 –
Derivative instruments – current – 19,869 –
Derivative instruments – non-current – – 562
Financial liabilities – 19,869 562
The Group had oil price sale financial hedges outstanding as at June 30, 2025 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
July 1, 2025 - December 31, 2025 11,700 WTI/WCS Differential USD -14.26/bbl
July 1, 2025 - December 31, 2025 10,000 WTI Sale Swap USD 71.30/bbl
July 1, 2025 - December 31, 2025 4,000 WTI Collar USD 65.00/bbl (Put)
USD 75.45/bbl (Call)
July 1, 2025 - December 31, 2025 2,000 Brent Sale Swap USD 75.78/bbl
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

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

20
The Group had gas price sale financial hedges outstanding as at June 30, 2025 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
July 1, 2025 - October 31, 2025 20,000 AECO Gas Swap CAD 2.25/GJ
July 1, 2025 - December 31, 2025 10,000 AECO Gas Swap CAD 2.50/GJ
The Group had electricity financial hedges outstanding as at June 30, 2025 which are summarized as follows:
Period Volume (MW) Type Average Pricing 
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
The Group entered into currency hedges to purchase :
(i) a total CAD 230 million for the period July 2025 to December 2025 at an average rate of CAD 1.36 (sell USD);
(ii) a total EUR 13.5 million for the period July 2025 to December 2025 at an average rate of EUR 1.07 (sell USD);
(iii) a total MYR 66 million for the period July 2025 to December 2025 at an average rate of MYR 4.39 (sell USD).
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 June 30, 2025:
CAD Millions 2025 2026 2027 2028 2029 Thereafter
Transportation service1 17.5 59.3 89.2 94.3 98.2 1,421.9
Power2 7.3 12.4 12.4 9.8 – –
Total commitments 24.8 71.7 101.6 104.2 98.2 1,421.9
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 July 1, 2025 to December 31, 
2028, an additional 5MWh at a weighted average price of CAD 58.31/MWh from July 1, 2025 to December 31, 2027, and an additional 5MWh at a 
weighted average price of CAD 46.85/MWh from July 1, 2025 to December 31, 2025.
20. RELATED PARTIES
The Group recognises the following related parties: associated companies, jointly controlled entities, key management personnel and 
members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or of its 
family or of any individual that controls, or has joint control or significant influence over the entity.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with 
parties at arm’s length.
During the first six month of 2025, the Group has not entered into material transactions with related parties.
21. SUBSEQUENT EVENTS
No events have occurred since June 30, 2025, that are expected to have a substantial effect on this report.                         
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2025 and 2024, UNAUDITED

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

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

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

Q2
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three and six months ended June 30, 2025

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Contents
Non-IFRS Measures
References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA), 
“operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under IFRS Accounting Standards (IFRS) and do not have any 
standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF , FCF , EBITDA, operating costs and net debt/net cash that may 
be used by other public companies. Management believes that OCF , FCF , EBITDA, operating costs and net debt/net cash are useful supplemental measures that may 
assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Non-IFRS measures should not be 
considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS measure is presented in this 
MD&A. See “Non-IFRS Measures” on page 18.
Forward-Looking Statements
Certain statements contained in this MD&A constitute “forward-looking statements” or “forward-looking information” (within the meaning of applicable securities 
legislation). Such statements and information (together, “forward-looking statements”) relate to future events, including the Corporation’s future performance, business 
prospects or opportunities.  Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, 
guidance, budgets, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“, 
“continue“, “estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, “might“, “should“, “believe“, “budget“ 
and similar expressions) are not statements of historical fact and may be “forward-looking statements“. Although IPC believes that the expectations and assumptions 
on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no 
assurances that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks 
and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks.  For additional information underlying 
forward-looking statements, refer to the “Cautionary Statement Regarding Forward-Looking Information” on page 23.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada are effective as of December 
31, 2024, and are included in the reports prepared by Sproule Associates Limited (Sproule), an independent qualified reserves evaluator, in accordance with National 
Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using 
Sproule’s December 31, 2024, price forecasts. 
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in France and Malaysia are effective as of 
December 31, 2024, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), an independent qualified reserves auditor, in accordance with NI 51-101 and 
the COGE Handbook, and using Sproule’s December 31, 2024, price forecasts. 
Certain abbreviations and technical terms used in this MD&A are defined or described under the heading “Other Supplementary Information”.
INTRODUCTION  3
HIGHLIGHTS  4
OPERATIONS REVIEW  5
• Business Overview 5
• Operations Overview  7
FINANCIAL REVIEW  9
• Financial Results 9
• Capital Expenditure 17
• Financial Position and Liquidity  17
• Non-IFRS Measures 18
• Off-Balance Sheet Arrangements  20
• Outstanding Share Data  20
• Contractual Obligations and Commitments  20
• Material Accounting Policies and Estimates 21
• Transactions with Related Parties  21
• Financial Risk Management  21
RISK FACTORS 22
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING  22
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION  23
RESERVES AND RESOURCES ADVISORY  25
OTHER SUPPLEMENTARY INFORMATION 27
2

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
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 August 5, 2025 and is intended to provide an overview of the Group’s 
operations, financial performance and current and future business opportunities. This MD&A should be read in conjunction with 
IPC’s unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2025 as well 
as the audited consolidated financial statements and accompanying notes for the year ended December 31, 2024 (“Financial 
Statements”).
Group Overview
The Group is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production 
assets and development projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in 
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada, under the Business Corporations Act. The 
address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is 
Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
Basis of Preparation
The MD&A and the Financial Statements have been prepared in accordance with IFRS Accounting Standards (“IFRS”) as issued by
the International Accounting Standards Board (“IASB”). 
Financial information is presented in United States Dollars (“USD”). However, as the Group operates in Europe and in Canada, 
certain financial information prepared by subsidiaries has been reported in Euros (“EUR”) and in Canadian Dollars (“CAD”). In 
addition, certain costs relating to the operations in Malaysia, which are reported in USD, are incurred in Malaysian Ringgit (“MYR”). 
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
Six months ended 
June 30, 2025
Six months ended
June 30, 2024
Twelve months ended
December 31, 2024
Average Period end Average Period end Average Year end
1 EUR equals USD 1.0930 1.1720 1.0812 1.0705 1.0821 1.0389
1 USD equals CAD 1.4102 1.3675 1.3583 1.3704 1.3698 1.4388
1 USD equals MYR 4.3772 4.2120 4.7270 4.7175 4.5759 4.4715
              
3

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
HIGHLIGHTS
Q2 2025 Business Highlights
• Average net production of approximately 43,600 boepd for the second quarter of 2025, within the guidance range for the 
period (52% heavy crude oil, 14% light and medium crude oil and 34% natural gas).(1)
• Continued progressing Phase 1 development activity as well as future phase resource maturation works at the Blackrod asset 
in Canada. 
• At Onion Lake Thermal, Canada, two of four planned production infill wells and the eighth Pad L sustaining well pair were 
brought online.
• Successfully completed the drilling and workover program at the Bertam Field, Malaysia during July 2025.
• 1.8 million IPC common shares purchased and cancelled during Q2 2025 under the normal course issuer bid (NCIB) and 
continuing with target to complete the full 2024/2025 NCIB this year.
Q2 2025 Financial Highlights
• Operating costs per boe of USD 17.8 for Q2 2025, marginally below guidance. (3)
• Operating cash flow (OCF) generation of MUSD 55 for Q2 2025, in line with guidance. (3)
• Capital and decommissioning expenditures of MUSD 100 for Q2 2025, in line with guidance.
• Free cash flow (FCF) generation for Q2 2025 amounted to MUSD -58 (MUSD 6 pre-Blackrod capital expenditures). (3)
• Gross cash of MUSD 79 and net debt of MUSD 375 as at June 30, 2025. (3)
• Net result of MUSD 14 for Q2 2025.
Reserves and Resources
• Total 2P reserves as at December 31, 2024 of 493 MMboe, with a reserve life index (RLI) of 31 years. (1)(2)
• Contingent resources (best estimate, unrisked) as at December 31, 2024 of 1,107 MMboe.(1)(2)
• 2P reserves net asset value (NAV) as at December 31, 2024 of MUSD 3,083 (10% discount rate). (1)(2)
2025 Annual Guidance
• Full year 2025 average net production guidance range forecast maintained at 43,000 to 45,000 boepd. (1)
• Full year 2025 operating costs guidance range forecast maintained at USD 18 to 19 per boe. (3)
• Full year 2025 OCF revised guidance estimated at between MUSD 245 and 260 (assuming Brent USD 60 to 75 per barrel for 
the remainder of 2025) from previous guidance of between MUSD 240 and 270. (3)(4)
• Full year 2025 capital and decommissioning expenditures guidance forecast maintained at MUSD 320 (including MUSD 230 
for the Blackrod asset).
• Full year 2025 FCF revised guidance estimated at between MUSD -135 and -120 (assuming Brent USD 60 to 75 per barrel for 
the remainder of 2025) from previous guidance of between MUSD -135 and -110.(3)(4)
Three months ended 
June 30
Six months ended 
June 30
USD Thousands 2025 2024 2025 2024
Revenue 158,892 219,040 337,384 425,459 
Gross profit 23,663 72,708 67,812 127,892 
Net result 13,850 45,210 30,081 78,929 
Operating cash flow(3) 54,873 101,941 129,663 191,242 
Free cash flow(3) (58,252) 7,559 (101,424) (35,752)
EBITDA(3) 51,519 103,971 122,465 190,991 
Net cash/(debt)(3) (374,977) (88,220) (374,977) (88,220)
4

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
OPERATIONS REVIEW 
Business Overview
During the second quarter of 2025, oil prices were volatile with Brent prices ranging from lows of USD 60 per barrel to highs of 
over USD 77 per barrel. The average Brent price for the quarter was approximately USD 68 per barrel, as compared to just below 
USD 76 per barrel for the first quarter of 2025. This second quarter volatility was driven by announcements early in the quarter by 
OPEC and the OPEC+ group to increase supply in excess of expectations, at the same time as the United States proposing high 
tariffs to countries deemed in a trade surplus of US goods. The US then delayed implementation of these tariffs which, combined 
with the increased conflicts in the Middle East, influenced higher world oil prices in early June. From the end of the quarter and 
into July 2025, Brent prices have remained more stable in a range just below USD 70 per barrel. Beyond the short-term shocks 
during the second quarter, global oil inventories remain below the 5-year average, high geopolitical tensions continue, and non-
OPEC oil production (in particular in the US) is unlikely to grow at current prices. These factors should be positive for future oil 
prices. During this large expenditure year for the Blackrod Phase 1 project, IPC continued to hedge oil prices in the second quarter 
of 2025 through zero cost collars. IPC’s oil hedges in total represent around 50% of our aggregate forecast 2025 oil production at 
around USD 76 and USD 71 per barrel for Dated Brent and West Texas Intermediate (WTI), respectively, as well as a WTI collar 
between USD 65 and USD 75 per barrel, for the remainder of 2025.  
 
In Canada, WTI to Western Canadian Select (WCS) crude price differentials during the second quarter of 2025 averaged USD 10.2 
per barrel. The WTI to WCS differential has benefited from the TMX pipeline expansion and tightened as the pipeline provides an 
alternative transportation route away from the US Gulf Coast. There are currently no tariffs on Canadian crude oil exports to the 
United States, which are covered by the US Mexico Canada free trade agreement. IPC has hedged the WTI to WCS differential for 
approximately 50% of our forecast 2025 Canadian oil production at USD 14 per barrel for 2025.
Natural gas markets in Canada for the second quarter of 2025 remained weak. The average AECO gas price was CAD 1.7 per 
Mcf for the second quarter of 2025 and IPC achieved an average realized price of CAD 1.8 per Mcf during the quarter. There is 
a potential for improved pricing for Canadian gas benchmark prices following the start-up of the LNG Canada project in British 
Columbia, which may relieve elevated Canadian gas inventories. Approximately 50% of our net long exposure is hedged at CAD 
2.4 per Mcf to end October 2025, dropping to around 15% for November and December at CAD 2.6 per mcf.
Second Quarter 2025 Highlights and Full Year 2025 Guidance 
During the second quarter of 2025, our portfolio delivered average net production of 43,600 boepd, in line with guidance. At Onion 
Lake Thermal, two infill wells and a Pad L sustaining well pair were brought online in the quarter. In Malaysia, the extended reach 
drilling and workover program was successfully completed with the new infill well A21 and worked over well A15 brought on 
stream at the end of July. Early indications are in line with expectations as the production wells go through an initial clean up and 
stabilisation period. We maintain the full year 2025 average net production guidance range of 43,000 to 45,000 boepd.(1)
Our operating costs per boe for the second quarter of 2025 was USD 17.8, marginally below guidance. Full year 2025 operating 
expenditure guidance of USD 18.0 to 19.0 per boe remains unchanged.(3)
Operating cash flow (OCF) generation for the second quarter of 2025 was MUSD 55. Full year 2025 OCF guidance is tightened to 
MUSD 245 to 260 (assuming Brent USD 60 to 75 per barrel for the remainder of 2025).(3)(4)
Capital and decommissioning expenditure for the second quarter of 2025 was MUSD 100 in line with guidance. Full year 2025 
capital and decommissioning expenditure of MUSD 320 is maintained.
Free cash flow (FCF) generation was MUSD -58 (MUSD 6 pre-Blackrod capital expenditures) during the second quarter of 2025. 
Full year 2025 FCF guidance is tightened to MUSD -135 to -120 (assuming Brent USD 60 to 75 per barrel for the remainder of 
2025) after taking into account MUSD 320 of forecast full year 2025 capital expenditures (including MUSD 230 relating to the 
Blackrod asset).(3)(4)
As at June 30, 2025, IPC’s net debt position increased to MUSD 375, from a net debt position of MUSD 314 as at March 31, 
2025, mainly driven by the funding of capital expenditures and the continuing share repurchase program (NCIB). Gross cash as at 
June 30, 2025 amounts to MUSD 79 and IPC has access to a Canadian revolving credit facility of greater than MUSD 180 (fully 
committed, available and undrawn as at June 30, 2025), following the increase of that facility from MCAD 180 to MCAD 250 during 
the second quarter. The access to liquidity supports IPC to follow through on its key strategic objectives of enhancing stakeholder 
value through organic growth, stakeholder returns, and pursuing value adding M&A.(3)
Blackrod
The Blackrod asset is 100% owned by IPC and contains 259 MMboe of 2P reserves and 1,025 MMboe of contingent resources 
(best estimate, unrisked) with regulatory approval to produce up to 80,000 bopd. In early 2023, IPC sanctioned the Phase 1 
development targeting plateau production rates of 30,000 bopd with a growth capital expenditure guidance of MUSD 850 and first 
oil expected in late 2026, marking the first major commercial Steam Assisted Gravity Drainage (SAGD) development undertaken 
in Alberta since the mid to late 2010s. The multi-year Phase 1 development guidance is maintained, with significant progress 
achieved to date. Since the Phase 1 project sanction to the end of Q2 2025, capital expenditures of MUSD 729 have been spent, 
or approximately 86% of the MUSD 850 growth capital guidance to first oil.(1)
5

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
All major work activities continued to advance in accordance with plan at the Blackrod asset during the second quarter. The final 
Central Processing Facility (CPF) module was delivered to site during the quarter, marking a significant milestone achievement for 
the project. Mechanical, electrical and instrumentation installations remain the key areas of focus for the CPF and well pad facilities 
prior to start-up. IPC remains strongly positioned to deliver the transformational Phase 1 development as planned. In parallel, with 
the responsible Phase 1 development activity, IPC is progressing future resource maturation works at Blackrod.
IPC intends to fund the remaining Blackrod capital expenditure with forecast cash flow generated by its operations, cash on hand 
and drawing under the existing Canadian credit facility if needed.(3)
Stakeholder Returns: Normal Course Issuer Bid
In Q4 2024, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 7.5 million common 
shares over the period of December 5, 2024 to December 4, 2025. Under the 2024/2025 NCIB, IPC repurchased and cancelled 
approximately 0.8 million common shares in December 2024, 5.5 million common shares during the first half of 2025, and a further 
0.2 million common shares purchased under other exemptions in Canada. The average price of common shares repurchased under 
the 2024/2025 NCIB during the first half of 2025 was around SEK 140 / CAD 19 per share.
As at June 30, 2025, IPC had a total of 113,354,532 common shares issued and outstanding and IPC held no common shares in 
treasury. As at July 31, 2025, IPC had a total of 113,278,532 common shares issued and outstanding and IPC held no common 
shares in treasury. Notwithstanding the final major capital investment year at Blackrod in 2025, IPC has purchased and cancelled 
approximately 85% of the maximum 7.5 million common shares allowed under the 2024/2025 NCIB by the end of July 2025 and 
intends to purchase and cancel the remaining 1.1 million common shares under that program in 2025. This would result in the 
cancellation of 6.2% of common shares outstanding as at the beginning of December 2024. IPC continues to believe that reducing 
the number of shares outstanding in combination with investing in long-life production growth at the Blackrod project will prove to 
be a winning formula for our stakeholders.
Environmental, Social and Governance (ESG) Performance
Alongside the publication of our second quarter 2025 financial report, IPC releases its sixth annual Sustainability Report. The 
Sustainability Report provides details on IPC’s approach to sustainability and material sustainability topics highlighting specific 
initiatives and progress. The Sustainability Report is available on IPC’s website at www.international-petroleum.com.
During the second quarter of 2025, 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. IPC has also made a commitment to maintain 2025 levels of 20 kg 
CO2/boe through to the end of 2028.(5)
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, 2024 (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 net present value (NPV), are 
described in the AIF . NAV is calculated as NPV less net debt of MUSD 209 as at December 31, 2024.
(3) Non-IFRS measures, see “Non-IFRS Measures” below.
(4) OCF and FCF forecasts at Brent USD 60 and 75 per barrel assume Brent to WTI differential of USD 3 and 5 per barrel, 
respectively, and WTI to WCS differential of USD 10 and 15 per barrel, respectively, for the remainder of 2025. OCF and 
FCF forecasts assume gas price on average of CAD 1.25 per Mcf for the third quarter of 2025 and CAD 2.50 per Mcf for the 
fourth quarter of 2025. 
(5) 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 six months ended June 30, 2025
Operations Overview 
Q2 2025 Overview
In Q2 2025, IPC continued to successfully demonstrate its commitment to operational excellence, delivering production 
performance and expenditure in line with our Capital Markets Day (CMD) guidance with no material safety or environmental 
incidents recorded in the quarter.
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 493 MMboe as at December 31, 2024, as certified by independent 
third party reserve auditors. The proved plus probable reserve life index (RLI) as at December 31, 2024, is approximately 31 years. 
Best estimate contingent resources as at December 31, 2024, are 1,107 MMboe (unrisked). See “Reserves and Resources 
Advisory” below.
Production
Average daily net production for Q2 2025 was in line with our CMD guidance at 43,600 boepd. In Canada, strong operational 
performance at the major oil and gas assets has been supplemented by a continued positive production response at the Mooney 
Phase 2 enhanced oil recovery (EOR) polymer flood. Stable performance continued at our Malaysian and French assets despite 
incurring planned well downtime during Bertam infill well drilling operations.
With strong operational delivery during the second quarter 2025, and a strong production outlook for the remainder of the
year, IPC remains well positioned to deliver an annual net average daily production within the guidance range of 43,000 to 45,000 
boepd. 
The production during Q2 2025 with comparatives is summarized below:
Production
in Mboepd
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2025 2024 2025 2024 2024
Crude oil
Canada – Northern Assets 13.6 14.5 13.8 14.7 14.2
Canada – Southern Assets 10.4 11.1 10.6 11.2 11.1
Malaysia 2.4 4.1 2.6 4.1 3.8
France 2.2 2.6 2.2 2.6 2.4
Total crude oil production 28.6 32.3 29.2 32.6 31.5
Gas
Canada – Northern Assets 0.4 0.5 0.4 0.4 0.5
Canada – Southern Assets 14.6 15.6 14.4 15.6 15.4
Total gas production 15.0 16.1 14.8 16.0 15.9
Total production 43.6 48.4 44.0 48.6 47.4
Quantity in MMboe 3.97 4.41 7.97 8.84 17.34
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
CANADA
Production
in Mboepd
Working 
Interest
(WI)
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2025 2024 2025 2024 2024
- Oil Onion Lake Thermal 100% 11.4 13.0 11.4 13.2 12.3
- Oil Suffield Area 100% 9.1 9.7 9.2 9.9 9.7
- Oil Other 50-100% 3.5 2.9 3.8 2.8 3.3
- Gas ~100% 15.0 16.1 14.8 16.0 15.9
Canada 39.0 41.7 39.2 41.9 41.2
7

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Production
Net production from IPC’s assets in Canada during Q2 2025 was in line with guidance at 39,000 boepd with continued strong 
operational performance at the major oil and gas producing assets. At Mooney, the Phase 2 EOR polymer flood project is 
performing ahead of expectations. Stable performance continued at Onion Lake Thermal during the quarter.
Organic Growth and Capital Projects
The Blackrod Phase 1 development project is progressing in line with schedule and budget. As at the end of Q2 2025, process 
facility fabrication is substantially complete with all facility pipe rack and equipment modules delivered to site. Critical equipment 
site installation, piping inter-connects, electrical and instrumentation installation continues to progress in line with plan and 
remains a key area of focus for the construction team. Drilling, completions and wellpad facilities installations are advancing as 
planned. Third-party transport pipeline installations are progressing on schedule. Commercial operational readiness is progressing 
in line with our progressive commissioning strategy to ensure a seamless transition from build to start-up. In addition, resource 
maturation works for future phase expansion continued during the second quarter of 2025.
At Onion Lake Thermal, two of the four planned production infill wells and the eighth Pad L sustaining well pair were brought 
online in the second quarter of 2025 with initial production performance in line with expectations. 
MALAYSIA
Production
in Mboepd WI
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2025 2024 2025 2024 2024
Bertam 100% 2.4 4.1 2.6 4.1 3.8
Production
Net production at Bertam in Malaysia in Q2 2025 was in line with guidance at 2,400 boepd with the planned well downtime during 
the drilling and workover operations.
Organic Growth and Capital Projects
In Malaysia, drilling of the planned infill well and well maintenance activity commenced in Q2 2025 and have progressed in line 
with schedule. A21 and A15 wells started production late July with early indications in line with expectation as well clean up and 
production testing is ongoing.
FRANCE
Production
in Mboepd WI
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2025 2024 2025 2024 2024
France
- Paris Basin 100%1 1.9 2.3 1.9 2.3 2.1
- Aquitaine 50% 0.3 0.3 0.3 0.3 0.3
2.2 2.6 2.2 2.6 2.4
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q2 2025 was in line with guidance at 2,200 boepd with stable performance across all the 
producing fields.   
Organic Growth
In France, field development studies continued in Q2 2025 with the next phase of production well targets matured and ready for 
sanction decision at IPC’s discretion.
8

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
FINANCIAL REVIEW 
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q2-25 Q1-25 Q4-24 Q3-24 Q2-24 Q1-24 Q4-23 Q3-23
Revenue 158,892 178,492 199,124 173,200 219,040 206,419 198,460 257,366
Gross profit 23,663 44,149 42,774 39,505 72,708 55,184 39,955 93,429
Net result 13,850 16,231 415 22,875 45,210 33,719 29,710 71,681
Earnings per share – USD 0.12 0.14 0.00 0.19 0.36 0.27 0.23 0.56
Earnings per share fully
diluted – USD 0.12 0.13 0.00 0.18 0.36 0.26 0.22 0.54
Operating cash flow1 54,873 74,790 78,158 72,589 101,941 89,301 73,634 119,142
Free cash flow1 (58,252) (43,172) (61,476) (38,269) 7,559 (43,311) (64,688) 34,703
EBITDA1 51,519 70,946 76,184 68,313 103,971 87,020 66,284 123,054
Net cash/(debt) at period end1 (374,977) (314,255) (208,528) (157,228) (88,220) (60,572) 58,043 83,097
1 See definition on page 18 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands June 30, 2025 December 31, 2024
Non-current assets 1,780,971 1,554,833
Current assets 242,905 398,849
Total assets 2,023,876 1,953,682
Total non-current liabilities 854,775 806,134
Current liabilities 206,486 208,078
Total liabilities 1,061,261 1,014,212
Net assets 962,615 939,470
Working capital (including cash) 36,419 190,771
9

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Selected Interim Financial Information
The Group operates within several geographical areas. Operating segments are reported at a country level, with Canada being 
further analyzed by main areas: (i) Canada – Northern Assets (comprising mainly of the Onion Lake Thermal asset) and (ii) Canada –
Southern Assets (comprising mainly of the Suffield assets, including the Brooks assets). This is consistent with the internal 
reporting provided to the CEO, who is the chief operating decision maker. The following tables present certain segment 
information.
Three months ended June 30, 2025
USD Thousands
Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 85,933 54,069 11,828 11,463 – 163,293
NGLs – 167 – – – 167
Gas 72 9,680 – – – 9,752
Net sales of oil and gas 86,005 63,916 11,828 11,463 – 173,212
Change in under/over lift position – – – 1,559 – 1,559
Royalties (11,932) (8,953) – (732) – (21,617)
Hedging settlement 2,236 3,139 – – – 5,375
Other operating revenue – – – 205 158 363
Revenue 76,309 58,102 11,828 12,495 158 158,892
Operating costs (19,786) (30,500) (11,768) (8,468) – (70,522)
Cost of blending (27,286) (5,983) – – – (33,269)
Change in inventory position (695) 380 203 (7) – (119)
Depletion (8,885) (12,652) (4,891) (2,893) – (29,321)
Depreciation of other assets – – (1,461) – – (1,461)
Exploration and business
development costs – – – – (537) (537)
Gross profit/(loss) 19,657 9,347 (6,089) 1,127 (379) 23,663
Three months ended June 30, 2024
USD Thousands
Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 115,482 75,536 39,341 17,253 – 247,612
NGLs – 275 – – – 275
Gas 44 6,631 – – – 6,675
Net sales of oil and gas 115,526 82,442 39,341 17,253 – 254,562
Change in under/over lift position – – – 2,215 – 2,215
Royalties (22,377) (11,912) – (1,161) – (35,450)
Hedging settlement (1,523) (1,121) – – – (2,644)
Other operating revenue – – – 237 120 357
Revenue 91,626 69,409 39,341 18,544 120 219,040
Operating costs (19,260) (30,541) (7,229) (7,804) – (64,834)
Cost of blending (34,876) (6,799) – – – (41,675)
Change in inventory position – (96) (4,829) 53 – (4,872)
Depletion (9,465) (13,021) (6,893) (3,282) – (32,661)
Depreciation of other assets – – (2,218) – – (2,218)
Exploration and business
development costs – – – – (72) (72)
Gross profit/(loss) 28,025 18,952 18,172 7,511 48 72,708
10

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Six months ended June 30, 2025
USD Thousands
Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 184,169 117,855 27,204 24,277 – 353,505
NGLs – 358 – – – 358
Gas 179 21,195 – – – 21,374
Net sales of oil and gas 184,348 139,408 27,204 24,277 – 375,237
Change in under/over lift position – – – 2,700 – 2,700
Royalties (25,052) (18,621) – (1,572) – (45,245)
Hedging settlement 1,393 2,766 – – – 4,159
Other operating revenue – – – 375 158 533
Revenue 160,689 123,553 27,204 25,780 158 337,384
Operating costs (38,966) (63,825) (20,349) (16,535) – (139,675)
Cost of blending (59,677) (11,318) – – – (70,995)
Change in inventory position 169 (156) 3,542 (174) – 3,381
Depletion (17,682) (24,954) (10,642) (5,059) – (58,337)
Depreciation of other assets – – (3,378) – – (3,378)
Exploration and business
development costs – – – – (568) (568)
Gross profit/(loss) 44,533 23,300 (3,623) 4,012 (410) 67,812
Six months ended June 30, 2024
USD Thousands
Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 219,627 141,007 57,894 33,970 – 452,498
NGLs – 519 – – – 519
Gas 169 20,923 – – – 21,092
Net sales of oil and gas 219,796 162,449 57,894 33,970 – 474,109
Change in under/over lift position – – – 5,131 – 5,131
Royalties (37,872) (20,900) – (2,300) – (61,072)
Hedging settlement 3,732 2,830 – – – 6,562
Other operating revenue – – – 454 275 729
Revenue 185,656 144,379 57,894 37,255 275 425,459
Operating costs (39,918) (69,772) (14,245) (16,715) – (140,650)
Cost of blending (73,170) (13,711) – – – (86,881)
Change in inventory position 368 (325) 210 152 – 405
Depletion (19,209) (26,181) (13,923) (6,501) – (65,814)
Depreciation of other assets – – (4,480) – – (4,480)
Exploration and business
development costs – – – – (147) (147)
Gross profit/(loss) 53,727 34,390 25,456 14,191 128 127,892
11

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Three and six months ended June 30, 2025, Review
Revenue
Revenue amounted to USD 158,892 thousand for Q2 2025, compared to USD 219,040 thousand for Q2 2024 and USD 337,384 
thousand for the first six months of 2025 compared to the USD 425,459 thousand for the first six months of 2024 is analyzed as 
follows: 
USD Thousands 
Three months ended June 30 Six months ended June 30
2025 2024 2025 2024
Crude oil sales 163,293 247,612 353,505 452,498
Gas and NGL sales 9,919 6,950 21,732 21,611
Change in under/overlift position 1,559 2,215 2,700 5,131
Royalties (21,617) (35,450) (45,245) (61,072)
Hedging settlement 5,375 (2,644) 4,159 6,562
Other operating revenue 363 357 533 729
Revenue 158,892 219,040 337,384 425,459
The main components of revenue for the three and six months ended June 30, 2025 and June 30, 2024, respectively, are detailed 
below: 
Crude oil sales
Three months ended June 30, 2025
USD Thousands
Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 85,933 54,069 11,828 11,463 163,293
- Quantity sold in bbls 1,614,538 1,010,851 175,829 167,394 2,968,612
- Average price realized USD per bbl 53.22 53.49 67.27 68.49 55.01
Three months ended June 30, 2024
USD Thousands
Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 115,482 75,536 39,341 17,253 247,612
- Quantity sold in bbls 1,739,097 1,119,518 421,810 203,008 3,483,433
- Average price realized USD per bbl 66.40 67.47 93.27 84.98 71.08
Crude oil revenue was 34% lower in Q2 2025 compared to Q2 2024 driven by prices and sales volumes.
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 Q2 2025, WTI averaged USD 64 per bbl compared to USD 81 per bbl for Q2 2024 and the 
average discount to WCS used in IPC’s pricing formula was USD 10 per bbl compared to USD 14 per bbl for the comparative 
period in 2024.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia
during Q2 2025 and two cargo liftings in Q2 2024. Produced unsold oil barrels from Bertam at the end of Q2 2025 amounted to 
152,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 68 per bbl for 
Q2 2025 compared to USD 85 per bbl for the comparative period in 2024.
12

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Six months ended June 30, 2025
USD Thousands
Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 184,169 117,855 27,204 24,277 353,505
- Quantity sold in bbls 3,303,184 2,092,938 370,960 336,416 6,103,498
- Average price realized USD per bbl 55.75 56.31 73.33 72.17 57.92
Six months ended June 30, 2024
USD Thousands
Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 219,627 141,007 57,894 33,970 452,498
- Quantity sold in bbls 3,565,871 2,246,532 624,329 404,612 6,841,344
- Average price realized USD per bbl 61.59 62.77 92.73 83.96 66.14
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 22% during the first six months of 2025 compared to the first six months of 2024 due to lower oil 
prices and lower production. 
The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. For the first six months of 2025, 
WTI averaged USD 68 per bbl compared to USD 79 per bbl for the comparative period and the average discount to WCS used in 
our pricing formula was USD 11 per bbl compared to USD 16 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 72 per bbl for the first six months of 2025 compared to USD 84 per bbl for the comparative period.
Gas and NGL sales
Three months ended June 30, 2025
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 72 9,847 9,919
- Quantity sold in Mcf 64,237 7,321,587 7,385,824
- Average price realized USD per Mcf 1.13 1.34 1.34
Three months ended June 30, 2024
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 44 6,906 6,950
- Quantity sold in Mcf 63,367 7,806,525 7,869,892
- Average price realized USD per Mcf 0.70 0.88 0.88
Gas and NGL sales revenue was 43% higher for the Q2 2025 compared to Q2 2024 mainly due to the higher achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For Q2 2025, IPC realized an average price of CAD 1.82 per 
Mcf compared to AECO average pricing of CAD 1.65 per Mcf.
13

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Six months ended June 30, 2025
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 179 21,553 21,732
- Quantity sold in Mcf 143,072 14,207,432 14,350,504
- Average price realized USD per Mcf 1.25 1.52 1.51
Six months ended June 30, 2024
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 169 21,442 21,611
- Quantity sold in Mcf 133,858 15,475,133 15,608,991
- Average price realized USD per Mcf 1.26 1.39 1.38
Gas and NGL sales revenue was 1% higher for the first six months of 2025 compared to the first six months of 2024 mainly due 
to the higher achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For the first six months of 2025, IPC realized an average price 
of CAD 2.10 per Mcf compared to AECO average pricing of CAD 1.89 per Mcf.
Hedging settlement
IPC enters into oil and gas prices risk management contracts in order to ensure a certain level of cash flow. It focuses mainly 
on oil and gas price swaps and on collars to a lesser extent, to mitigate these commodities price exposure. Oil and gas hedging 
contracts are not entered into for speculative purposes and only account for a portion of our production.
The realized hedging settlement for the first six months of 2025 amounted to a gain of USD 4,159 thousand and consisted of a 
gain of USD 2,464 thousand on the oil contracts and a gain of USD 1,695 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 103,910 thousand for Q2 2025 compared to USD 111,381 
thousand for Q2 2024 and USD 207,288 thousand for the first six months of 2025 compared to USD 227,126 thousand for the first 
six months of 2024, and is analyzed as follows:
Three months ended June 30, 2025
USD Thousands
Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 19,786 30,500 12,075 8,468 (307) 70,522
USD/boe2 15.47 13.42 55.10 42.40 n/a 17.76
Cost of blending 27,286 5,983 – – – 33,269
Change in inventory position 696 (380) (203) 7 – 119
Production costs 47,767 36,103 11,872 8,475 (307) 103,910
Three months ended June 30, 2024
USD Thousands
Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 19,260 30,541 11,369 7,804 (4,140) 64,834
USD/boe2 14.10 12.55 30.76 33.13 n/a 14.72
Cost of blending 34,876 6,799 – – – 41,675
Change in inventory position – 96 4,829 (53) – 4,872
Production costs 54,136 37,436 16,198 7,751 (4,140) 111,381
14

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Six months ended June 30, 2025
USD Thousands
Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 38,966 63,825 23,877 16,535 (3,528) 139,675
USD/boe2 15.14 14.09 50.08 42.73 n/a 17.53
Cost of blending 59,677 11,318 – – – 70,995
Change in inventory position (169) 156 (3,542) 174 – (3,381)
Production costs 98,474 75,299 20,335 16,709 (3,528) 207,289
Six months ended June 30, 2024
USD Thousands
Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 39,918 69,772 22,435 16,715 (8,190) 140,650
USD/boe2 14.50 14.30 30.05 35.97 n/a 15.91
Cost of blending 73,170 13,711 – – – 86,881
Change in inventory position (368) 325 (210) (152) – (405)
Production costs 112,720 83,808 22,225 16,563 (8,190) 227,126
1  See definition on page 18 under “Non-IFRS measures”.
2  USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and for 2024.
3Included 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 53.70 for Q2 2025 and USD 19.56 for the comparative period and USD 42.68 and USD 19.08 for the six months ended 
June 30, 2025, and June 30, 2024, respectively.
Operating costs
Operating costs amounted to USD 70,522 thousand for Q2 2025 compared to USD 64,834 thousand for Q2 2024 and USD
139,675 thousand for the first six months of 2025 compared to USD 140,650 thousand for the first six months of 2024. Operating 
costs per boe amounted to USD 17.76 per boe in Q2 2025 marginally below the guidance for the quarter and compared with USD 
14.72 per boe in Q2 2024.
Operating costs per boe in Malaysia increased in Q2 2025 compared to Q2 2024 due to lower production with one production well 
offline awaiting workover intervention planned in Q3 2025. 
Cost of blending
For the Suffield area and Onion Lake Thermal assets in Canada, oil production is blended with purchased diluent to meet pipeline 
specifications. As a result of the blending, actual sales volumes are higher than produced barrels and the realized sales price of a 
blended barrel is higher than an unblended barrel.
The cost of the diluent amounted to USD 33,269 thousand for Q2 2025 compared to USD 41,675 thousand for Q2 2024 and USD
70,995 thousand for the first six months of 2025 compared to USD 86,881 thousand for the comparative period. 
Change in inventory position
The Bertam field in Malaysia is located offshore and production is lifted and sold from the FPSO Bertam when a cargo parcel size 
is reached. Accordingly, the timing of a lifting varies based on the inventory level on the FPSO facility and the change in inventory 
position varies, both positively and negatively, from period to period. Inventories are valued at the lower of cost including depletion, 
and market value, and the difference in the valuation between period ends is reflected in the change in inventory position in the 
statement of operations. At the end of Q2 2025, IPC had crude entitlement of 152,000 bbls of oil on the FPSO Bertam facility 
being crude produced but not yet sold. 
Depletion costs
The total depletion of oil and gas properties amounted to USD 29,321 thousand for Q2 2025 compared to USD 32,661 thousand 
for Q2 2024 and USD 58,337 thousand for the first six months of 2025 compared to USD 65,814 thousand for the first six months 
of 2024.
15

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
The depletion charge is analyzed in the following tables:
Three months ended June 30, 2025
USD Thousands
Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 8,885 12,652 4,891 2,893 29,321
USD per boe2 6.95 5.57 22.32 14.48 7.38
Three months ended June 30, 2024
USD Thousands
Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,465 13,021 6,893 3,282 32,661
USD per boe2 6.93 5.35 18.65 13.93 7.41
Six months ended June 30, 2025
USD Thousands
Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 17,682 24,954 10,642 5,059 58,337
USD per boe2 6.87 5.51 22.32 13.07 7.32
Six months ended June 30, 2024
USD Thousands
Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 19,209 26,181 13,923 6,501 65,814
USD per boe2 6.98 5.37 18.65 13.99 7.44
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.
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 period due to lower production with one production 
well offline awaiting workover intervention planned in Q3 2025. Overall though, depletion costs on a USD per boe basis have been 
very stable.
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 1,461 thousand for Q2 2025 compared to USD 2,218 thousand for Q2 
2024 and USD 3,378 thousand for the first six months of 2025 compared to USD 4,480 thousand for the first six months of 2024. 
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 568 thousand for the first six months of 2025 
and USD 147 thousand for the first six months of 2024.
Net financial items
Net financial items amounted to a gain of USD 159 thousand for Q2 2025, compared to a charge of USD 10,048 thousand for Q2 
2024 and a charge of USD 18,696 thousand for the first six months of 2025 compared to a charge of USD 19,818 thousand for the 
first six months of 2024, and included a realized currency hedge loss and a net foreign exchange gain of respectively USD 7,518 
thousand and USD 14,233 thousand for the first six months of 2025 compared to no realized currency hedges and a net foreign 
exchange loss of USD 3,617 thousand for the first six months of 2024. The foreign exchange movements are mainly resulting 
from the revaluation of intra-group loan funding balances and are non-cash items.
Excluding foreign exchange movements and realized currency cashflow hedges, the net financial items amounted to a charge of 
USD 13,396 thousand for Q2 2025, compared to USD 8,492 thousand for Q2 2024 and a charge of USD 25,411 thousand for the 
first six months of 2025 compared to a charge of USD 16,201 thousand for the first six months of 2024.
16

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
The interest expense are very stable and amounted to USD 8,980 thousand for Q2 2025, compared to USD 8,928 thousand for the 
comparative period in 2024 and USD 17,741 thousand for the first six months of 2025 compared to USD 17,746 thousand for the 
first six months of 2024 and mainly related to the bond interest at a coupon rate of 7.25% per annum. Interest income generated 
on cash balances held amounted to USD 694 thousand for Q2 2025 and USD 4,917 thousand for Q2 2024 and USD 2,328 
thousand for the first six months of 2025 compared to USD 10,534 thousand for the first six months of 2024.
The unwinding of the asset retirement obligation discount rate amounted to USD 4,115 thousand for Q2 2025 compared to USD 
3,641 thousand for Q2 2024 and USD 8,072 thousand for the first six months of 2025 compared to USD 7,259 thousand for the 
first six months of 2024. 
Income tax
The corporate income tax amounted to a charge of USD 6,167 thousand for Q2 2025, compared to a charge of USD 13,470 
thousand for the comparative period and a charge of USD 10,846 thousand for the first six months of 2025 compared to a charge
of USD 21,216 thousand for the comparative period.
The current income tax amounted to a charge of USD 337 thousand for Q2 2025 and USD 851 thousand during the first six 
months of 2025 and mainly related to France. No corporate income tax is expected to be payable in Canada in 2025 due to the 
usage of historical tax pools. 
Capital Expenditure
Development and exploration and evaluation expenditures incurred for the first six months of 2025 was as follows:
USD Thousands
Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 159,831 4,896 24,652 4,033 193,412
Exploration and evaluation 3,399 – – – 3,399
163,230 4,896 24,652 4,033 196,811
Capital expenditures of USD 196,811 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project and in 
Malaysia for the A21 infill well drilling.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 13,242 thousand as at June 30, 2025, which included USD 11,419 thousand in 
respect of the FPSO Bertam. The FPSO Bertam is being depreciated to its residual value on a unit of production basis to August 
2025.
Financial Position and Liquidity
Financing 
As at June 30, 2025, IPC had MUSD 450 of bonds outstanding, maturing in February 2027 with a fixed coupon rate of 7.25% per 
annum, payable in semi-annual instalments in August and February. The bond repayment obligations as at June 30, 2025, are 
classified as non-current as there are no mandatory repayments within the next twelve months.
In addition, as at June 30, 2025, the Group had a revolving credit facility of MCAD 250 (the “Canadian RCF”) in connection with 
its oil and gas assets in Canada. During Q2 2025, the Group increased the Canadian RCF from MCAD 180 to MCAD 250 and 
extended the maturity date. The Canadian RCF has a maturity in May 2027 and was undrawn and fully available as at June 30, 
2025. During 2024, the Group entered into a letter of credit facility in Canada (the “LC Facility”) to cover existing operational 
letters of credit. As at June 30, 2025, operational letters of credit in an aggregate of MCAD 40.2 have been issued under the LC 
Facility, including letters of credit of MCAD 35 to support the third party pipeline construction agreements for the Blackrod Phase 1 
Development project which are expected to be released when these pipelines become operational.
As at June 30, 2025, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May 2026. IPC 
makes quarterly repayments of the France Facility. The amount remaining outstanding under the France Facility as at June 30, 
2025 was MUSD 3.9 which 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 other credit facilities as at June 30, 2025.
Net debt as at June 30, 2025 amounted to MUSD 375. Cash and cash equivalents held amounted to MUSD 79 as at June 30, 
2025.
IPC intends to fund the remaining Blackrod capital expenditures with forecast cash flow generated by its operations, cash on hand 
and Canadian RCF loan drawing if needed.
17

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Working Capital 
As at June 30, 2025, the Group had a working capital balance including cash of USD 36,419 thousand compared to USD 190,771 
thousand as at December 31, 2024. The difference as at June 30, 2025, from December 31, 2024, is mainly 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 including net sales of diluent less current tax. Operating cash 
flow is used to analyze the amount of cash that is being generated available for capital investment and servicing debt.
“Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures 
less general, 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 June 30 Six months ended June 30
2025 2024 2025 2024
Revenue 158,892 219,040 337,384 425,459 
Production costs and net sales of diluent to third party1 (103,682) (111,381) (206,870) (227,126)
Current tax (337) (5,718) (851) (7,091)
Operating cash flow 54,873 101,941 129,663 191,242 
1 Includes net sales of diluent to third party amounting to USD 228 thousand for the second quarter of 2025 and USD 419 thousand for the first six 
months of 2025.
18

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
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 June 30 Six months ended June 30
2025 2024 2025 2024
Operating cash flow - see above 54,873 101,941 129,663 191,242 
Capital expenditures (97,925) (84,101) (196,811) (209,357)
Abandonment and farm-in expenditures1 (2,097) (2,241) (2,418) (2,363)
General, administration and depreciation expenses before 
depreciation2 (3,691) (3,689) (8,049) (7,342)
Cash financial items3 (9,412) (4,351) (23,809) (7,932)
Free cash flow (58,252) 7,559 (101,424) (35,752)
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.
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended June 30 Six months ended June 30
2025 2024 2025 2024
Net result 13,850 45,210 30,081 78,929 
Net financial items (159) 10,048 18,696 19,818 
Income tax 6,167 13,470 10,846 21,216 
Depletion and decommissioning costs 29,321 32,661 58,337 65,814 
Depreciation of other tangible fixed assets 1,461 2,218 3,378 4,480 
Exploration and business development costs 537 72 568 147
Sale of assets1 (10) – (104) –
Depreciation included in general, administration and depreciation 
expenses2 352 292 663 587 
EBITDA 51,519 103,971 122,465 190,991 
1  Sale of assets is included under “Other income/(expense)“ but not specifically disclosed in the Financial Statements 
2  Item is not shown in the Financial Statements.
Operating costs
The following table sets out how operating costs is calculated: 
USD Thousands
Three months ended June 30 Six months ended June 30
2025 2024 2025 2024
Production costs 103,910 111,381 207,289 227,126 
Cost of blending (33,269) (41,675) (70,995) (86,881)
Change in inventory position (119) (4,872) 3,381 405 
Operating costs 70,522 64,834 139,675 140,650 
19

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Net cash/(debt)
The following table sets out how net cash/(debt) is calculated: 
USD Thousands June 30, 2025 December 31, 2024
Bank loans (3,863) (5,121)
Bonds1 (450,000) (450,000)
Cash and cash equivalents 78,886 246,593 
Net cash/(debt) (374,977) (208,528)
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 1.0 in respect of its obligations related to the Ferguson asset; (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 in respect of its 
obligations related to Blackrod Phase 1 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, 2024, IPC had a total of 126,992,066 common shares issued and outstanding, with no common shares held in 
treasury. From January 1, 2024 to December 4, 2024, IPC purchased and cancelled a total of 7,109,365 common shares under 
the normal course issuer bid/share repurchase program (NCIB). The NCIB was further renewed in Q4 2024 and IPC is entitled to 
purchase up to 7,465,356 common shares over the period of December 5, 2024 to December 4, 2025. During December 2024, 
IPC purchased 823,386 and cancelled 713,230 common shares under the renewed NCIB, for an aggregate of 7,822,595 common 
shares cancelled in 2024. 
As at December 31, 2024, IPC had a total of 119,169,471 common shares issued and outstanding and held 110,156 common 
shares held in treasury.
Over the period of January 1, 2025 to June 30, 2025, IPC purchased 5,492,965 common shares under the NCIB and 211,818 
common shares under certain other exemptions in Canada. All of these purchased common shares, including the common shares 
held in treasury as at December 31, 2024, were cancelled during the first six months of 2025. As at June 30, 2025, IPC had a total 
of 113,354,532 common shares issued and outstanding, with no 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 42,597,533 
common shares in IPC, representing 37.6% of the outstanding common shares as at June 30, 2025.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares.
IPC has 2,941,020 IPC Share Unit Plan awards outstanding as at August 5, 2025, of which 948,938 awards were granted in 2025.
The Corporation is authorized to issue an unlimited number of common shares without par value. The Corporation is also 
authorized to issue an unlimited number of class A preferred shares and an unlimited number of class B preferred shares, issuable 
in series.
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 June 30, 2025: 
MCAD 2025 2026 2027 2028 2029 Thereafter
Transportation service1  17.5     59.3     89.2     94.3    98.2  1,421.9    
Power2  7.3     12.4     12.4     9.8    – –    
Total commitments  24.8     71.7     101.6     104.2    98.2  1,421.9    
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 July 1, 2025 to December
31, 2028, an additional 5MWh at a weighted average price of CAD 58.31/MWh from July 1, 2025 to December 31, 2027, and an additional
5MWh at a weighted average price of CAD 46.85/MWh from July 1, 2025 to December 31, 2025.
20

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
Material Accounting Policies and Estimates
In connection with the preparation of the Corporation’s consolidated financial statements, management has made assumptions 
and estimates about future events and applied judgments that affect the reported values of assets, liabilities, revenues, expenses 
and related disclosures. These assumptions, estimates and judgments are based on historical experience, current trends and other 
factors that they believe to be relevant at the time the financial statements are prepared. The management reviews the accounting 
policies, assumptions, estimates and judgments to ensure that the financial statements are presented fairly in accordance with 
IFRS. However, because future events and their effects cannot be determined with certainty, actual results could differ from these 
assumptions and estimates, and such differences could be material.
Transactions with Related Parties 
The Group recognises the following related parties: associated companies, jointly controlled entities, key management personnel
and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or
of its family or of any individual that controls, or has joint control or significant influence over the entity.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with
parties at arm’s length.
During the first six months of 2025, the Group has not entered into material transactions with related parties.
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 June 30, 2025, the Corporation had entered into oil, gas, electricity 
and currency 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 June 30, 2025, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
July 1, 2025 - December 31, 2025 11,700 WTI/WCS Differential USD -14.26/bbl
July 1, 2025 - December 31, 2025 10,000 WTI Sale Swap USD 71.30/bbl
July 1, 2025 - December 31, 2025 4,000 WTI Collar USD 65.00/bbl (Put)
USD 75.45/bbl (Call)
July 1, 2025 - December 31, 2025 2,000 Brent Sale Swap USD 75.78/bbl
21

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
The Group had gas price sale financial hedges outstanding as at June 30, 2025, which are summarized as follows:
Period Volume (Gigajoules (GJ) per
day)) Type Average Pricing 
July 1, 2025 - October 31, 2025 20,000 AECO Swap CAD 2.25/GJ
July 1, 2025 - December 31, 2025 10,000 AECO Swap CAD 2.50/GJ
The Group had electricity financial hedges outstanding as at June 30, 2025, 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 21,683 thousand as at June 30, 2025.
Currency Risk
The Group’s policy on currency rate hedging is, in the case of currency exposure, to consider fixing the rate of exchange. The 
Group will take into account the currency exposure, current rates of exchange and market expectations in comparison to historic 
trends and volatility in making the decision to hedge.
The Group entered into currency hedges to purchase:
(i) a total CAD 230 million for the period July 2025 to December 2025 at an average rate of CAD 1.36 (sell USD);
(ii) a total EUR 13.5 million for the period July 2025 to December 2025 at an average rate of EUR 1.07 (sell USD);
(iii) a total MYR 66 million for the period July 2025 to December 2025 at an average rate of MYR 4.39 (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 negative fair value of USD 2,347 thousand as at June 30, 2025.
Interest Rate Risk
Interest rate risk is the risk to earnings due to uncertain future interest rates on borrowings. The Group will take into account the 
level of external debt, current interest rates and market expectations in comparison to historic trends and volatility in making the 
decision to hedge. There are currently no interest rate hedges.
Credit Risk
The Group may be exposed to third party credit risk through contractual arrangements with counterparties who buy the Group’s 
hydrocarbon products. The Group’s policy is to limit credit risk by only entering into oil and gas sales agreements with reputable 
and creditworthy oil and gas and trading companies. Where it is determined that there is a credit risk for oil and gas sales, the 
Group’s policy is to require credit enhancement from the purchaser.
The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take 
possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In 
addition, cash is to be held and transacted only through major banks.
RISK FACTORS 
IPC is engaged in the exploration, development and production of oil and gas and 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, 2024 (”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.
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.
22

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
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 three and six months ended 
June 30, 2025, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial 
reporting. 
Control Framework 
Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control
– Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission 
(COSO). Management concluded that the Corporation’s internal control over financial reporting was effective as of June 30, 2025.  
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: 
• 2025 production ranges (including total daily average production), production composition, cash flows, operating costs and 
capital and decommissioning expenditure estimates; 
• Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business 
plans and assumptions regarding the business environment, which are subject to change; 
• IPC’s financial and operational flexibility to navigate the Corporation through periods of volatile commodity prices; 
• The ability to fully fund future expenditures from cash flows and current borrowing capacity; 
• IPC’s intention and ability to continue to implement its strategies to build long-term shareholder value; 
• The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth; 
• The continued facility uptime and reservoir performance in IPC’s areas of operation; 
• Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing, 
regulatory approvals, third party commercial arrangements, breakeven oil prices and net present values;
• 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 return of value to IPC’s shareholders as a result of the NCIB;
• IPC’s ability to implement its greenhouse gas (GHG) emissions intensity and climate strategies and to achieve its net GHG 
emissions intensity reduction targets;
• IPC’s ability to implement projects to reduce net emissions intensity, including potential carbon capture and storage;
• Estimates of reserves and contingent resources; 
• The ability to generate free cash flows and use that cash to repay debt;
• IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the 
Corporation; 
• IPC’s ability to identify and complete future acquisitions;
• Expectations regarding the oil and gas industry in Canada, Malaysia and France, including assumptions regarding future 
royalty rates, regulatory approvals, legislative changes, tariffs, and ongoing projects and their expected completion; and
• Future drilling and other exploration and development activities.
Statements relating to “reserves“ and “contingent resources“ are also deemed to be forward-looking statements, as they involve 
the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the 
quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery 
of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of 
management. See also “Reserves and Resources Advisory“.
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Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations 
and assumptions concerning: the potential impact of tariffs implemented in 2025 by the U.S. and Canadian governments and that 
other than the tariffs that have been implemented, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, or 
imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any 
other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and 
natural gas; prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future 
well production rates and reserve and contingent resource volumes; operating costs; 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
• Political or economic developments, including, without limitation, the risk that (i) one or both of the U.S. and Canadian 
governments increases the rate or scope of tariffs implemented in 2025, or imposes new tariffs on the import of goods from 
one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction 
or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the 
tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, 
U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Corporation; and
• Changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations. 
Readers are cautioned that the foregoing list of factors is not exhaustive. See also “Risk Factors”.
Estimated production and FCF generation are based on IPC’s current business plans over the periods of 2025 to 2029 and 2030 to 
2034, less net debt of MUSD 209 as at December 31, 2024, with assumptions based on the reports of IPC’s independent reserves 
evaluators, and including certain corporate adjustments relating to estimated general and administration costs and hedging, and 
excluding shareholder distributions and financing costs. Assumptions include average net production of approximately 57 Mboepd 
over the period of 2025 to 2029, average net production of approximately 63 Mboepd over the period of 2030 to 2034, average 
Brent oil prices of USD 75 to 95 per bbl escalating by 2% per year, and average Brent to Western Canadian Select differentials 
and average gas prices as estimated by IPC’s independent reserves evaluator and as further described in the AIF . IPC’s current 
business plans and assumptions, and the business environment, are subject to change. Actual results may differ materially from 
forward-looking estimates and forecasts.
Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the 
Financial Statements, the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2024 (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).
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Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
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, 2024, and are included in the reports prepared by Sproule Associates Limited (Sproule), 
an independent qualified reserves evaluator, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and 
Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule’s December 
31, 2024 price forecasts.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in 
France and Malaysia are effective as of December 31, 2024, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), 
an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 
31, 2024 price forecasts.
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, 2024 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 493 MMboe as at December 31, 2024, by the mid-point of 
the 2025 CMD production guidance of 43,000 to 45,000 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.
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Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
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
June 30, 2025 22.7 5.9 89.8 MMcf                     
(15.0 Mboe) 43.6
June 30, 2024 24.3 8.0 96.5 MMcf                     
(16.1 Mboe) 48.4
Six months ended
June 30, 2025 23.0 6.2 89.0 MMcf                     
(14.8 Mboe) 44.0
June 30, 2024 24.6 8.0 96.2 MMcf                     
(16.0 Mboe) 48.6
Year ended December 31, 2024
December 31, 2024 23.9 7.7 95.1MMcf                     
(15.8 Mboe) 47.4
This MD&A also makes reference to IPC’s forecast total average daily production of 43,000 to 45,000 boepd for 2025. IPC 
estimates that approximately 52% of that production will be comprised of heavy oil, approximately 15% will be comprised of light 
and medium crude oil and approximately 33% will be comprised of conventional natural gas.
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Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
OTHER SUPPLEMENTARY INFORMATION
Abbreviations
CAD  Canadian dollar
MCAD  Million Canadian dollar
EUR  Euro
USD  US dollar
MUSD  Million US dollar
MYR  Malaysian Ringgit
FPSO  Floating Production Storage and Offloading (facility)
Oil related terms and measurements
AECO   The daily average benchmark price for natural gas at the AECO hub in southeast Alberta                                                                            
AESO  Alberta Electric System Operator
API   An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale
ASP   Alkaline surfactant polymer (an EOR process)
bbl   Barrel (1 barrel = 159 litres)
boe   Barrels of oil equivalents
boepd   Barrels of oil equivalents per day
bopd   Barrels of oil per day
Bcf  Billion cubic feet
C5  Condensate
CO2e  Carbon dioxide equivalents, including carbon dioxide, methane and nitrous oxide
Empress   The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border
EOR   Enhanced Oil Recovery
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
WTI   West Texas Intermediate
WCS   Western Canadian Select
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Management’s Discussion and Analysis
For the three and six months ended June 30, 2025
DIRECTORS
C. Ashley Heppenstall
Director, Chair
London, England
William Lundin
Director, President and Chief Executive Officer
Coppet, Switzerland
Chris Bruijnzeels
Director
Abcoude, The Netherlands
Donald K. Charter
Director
Toronto, Ontario, Canada
Lukas (Harry) H. Lundin
Director
Toronto, Ontario, Canada
Emily Moore
Director
Toronto, Ontario, Canada
Mike Nicholson
Director
Monaco
Deborah Starkman
Director
Toronto, Ontario, Canada
OFFICERS
William Lundin
President and Chief Executive Officer
Coppet, Switzerland
Christophe Nerguararian
Chief Financial Officer
Geneva, Switzerland
Nicki Duncan
Chief Operating Officer
Geneva, Switzerland
Jeffrey Fountain
General Counsel and Corporate Secretary
Geneva, Switzerland
Rebecca Gordon
Senior Vice President Corporate Planning and 
Investor Relations
Geneva, Switzerland 
Chris Hogue
Senior Vice President, Canada
Calgary, Alberta, Canada
Ryan Adair
Vice President Asset Management and
Corporate Planning, Canada
Calgary, Alberta, Canada
Curtis White
Vice President Commercial, Canada
Calgary, Alberta, Canada
MEDIA AND INVESTOR RELATIONS
Robert Eriksson 
Stockholm, Sweden
CORPORATE OFFICE
Suite 2800, 1055 Dunsmuir Street Vancouver, 
British Columbia
V7X 1L2 Canada
Telephone: +1 604 689 7842
Website: www.international-petroleum.com
OPERATIONS OFFICE
5 Chemin de la Pallanterie
1222 Vésenaz
Switzerland
Telephone: +41 22 595 10 50
E-mail: info@international-petroleum.com
REGISTERED AND RECORDS OFFICE
Suite 3500, 1133 Melville Street 
Vancouver, British Columbia
V6E 4E5 Canada
INDEPENDENT AUDITORS
PricewaterhouseCoopers LLP , Canada
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta, and Toronto, Ontario
STOCK EXCHANGE LISTINGS
Toronto Stock Exchange and NASDAQ Stockholm 
Trading Symbol: IPCO
28

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