FULLTEXT DEL 1 AV 1
Kvartalsrapport Q3 2025
===== SIDA 1 =====
Q3
International Petroleum Corporation
Interim Condensed Consolidated
Financial Statements
For the three and nine months ended September 30, 2025
===== SIDA 2 =====
2
Contents
Interim Condensed Consolidated Statement of Operations 3
Interim Condensed Consolidated Statement of Comprehensive Income/(Loss) 4
Interim Condensed Consolidated Balance Sheet 5
Interim Condensed Consolidated Statement of Cash Flow 6
Interim Condensed Consolidated Statement of Changes in Equity 7
Notes to the Interim Condensed Consolidated Financial Statements 8
Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
===== SIDA 3 =====
3
Interim Condensed Consolidated Statement of Operations
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
Three months ended
September 30
Nine months ended
September 30
USD Thousands Note 2025 2024 2025 2024
Revenue 2 172,297 173,200 509,681 598,659
Cost of sales
Production costs 3 (106,383) (100,984) (313,672) (328,110)
Depletion and decommissioning costs 8 (32,245) (30,491) (90,582) (96,305)
Depreciation of other tangible fixed assets 8 (1,419) (2,023) (4,797) (6,503)
Exploration and business development costs (184) (197) (752) (344)
Gross profit 2 32,066 39,505 99,878 167,397
Other income/(expenses) 91 – 614 –
General and administrative expenses (4,295) (4,249) (13,007) (12,178)
Profit before financial items 27,862 35,256 87,485 155,219
Finance income 4 501 9,472 11,331 16,389
Finance costs 5 (21,531) (13,596) (51,057) (40,331)
Net financial items (21,030) (4,124) (39,726) (23,942)
Profit before tax 6,832 31,132 47,759 131,277
Income tax expense 6 (3,030) (8,257) (13,876) (29,473)
Net result 3,802 22,875 33,883 101,804
Net result attributable to:
Shareholders of the Parent Company 3,801 22,874 33,878 101,788
Non-controlling interest 1 1 5 16
3,802 22,875 33,883 101,804
Earnings per share – USD
1 14 0.03 0.19 0.29 0.81
Earnings per share fully diluted – USD1 14 0.03 0.18 0.28 0.80
1 Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the interim condensed consolidated financial statements
===== SIDA 4 =====
4
Interim Condensed Consolidated Statement of Comprehensive Income/(Loss)
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
Three months ended
September 30
Nine months ended
September 30
USD Thousands Note 2025 2024 2025 2024
Net result 3,802 22,875 33,883 101,804
Other comprehensive income/(loss)
Items that may be reclassified to profit or loss:
Reclassification of hedging (gains)/losses to profit or
loss 2,4,5 (6,066) 23,464 (2,707) (11,302)
(Loss)/Gain on cash flow hedges (5,655) (5,366) 31,994 (11,928)
Income tax relating to these items 2,914 (4,294) (6,856) 5,639
Currency translation adjustments (17,062) 14,772 35,979 (16,439)
Total comprehensive income/(loss) (22,067) 51,451 92,293 67,774
Total comprehensive income attributable to:
Shareholders of the Parent Company (22,068) 51,437 92,283 67,760
Non-controlling interest 1 14 10 14
(22,067) 51,451 92,293 67,774
See accompanying notes to the interim condensed consolidated financial statements
===== SIDA 5 =====
5
Interim Condensed Consolidated Balance Sheet
As at September 30, 2025 and December 31 2024, UNAUDITED
USD Thousands Note September 30, 2025 December 31, 2024
ASSETS
Non-current assets
Exploration and evaluation assets 7 4,039 480
Property, Plant and Equipment 8 1,736,124 1,500,912
Right-of-use assets 3,367 3,103
Deferred tax assets 6 1,363 1,673
Derivative instruments 18 1,774 –
Other non-current assets 9 52,005 48,665
Total non-current assets 1,798,672 1,554,833
Current assets
Inventories
10 25,184 20,073
Trade and other receivables 11 85,317 127,450
Derivative instruments 18 12,069 3,219
Current tax receivables 3,472 1,514
Cash and cash equivalents 12 44,661 246,593
Total current assets 170,703 398,849
TOTAL ASSETS 1,969,375 1,953,682
LIABILITIES
Non-current liabilities
Financial liabilities
15 26,576 1,719
Bonds 15 443,496 439,862
Lease liabilities 2,876 2,728
Provisions 16 286,493 268,509
Deferred tax liabilities 6 118,300 92,754
Derivative instruments 18 – 562
Total non-current liabilities 877,741 806,134
Current liabilities
Trade and other payables
17 157,179 176,371
Financial liabilities 18 2,907 3,402
Derivative instruments 18 2,097 19,869
Current tax liabilities 109 1,146
Lease liabilities 877 573
Provisions 16 7,022 6,717
Total current liabilities 170,191 208,078
EQUITY
Shareholders’ equity 921,293 939,315
Non-controlling interest 150 155
Net shareholders’ equity 921,443 939,470
TOTAL EQUITY AND LIABILITIES 1,969,375 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 nine months ended September 30, 2025 and 2024, UNAUDITED
Three months ended
September 30
Nine months ended
September 30
USD Thousands Note 2025 2024 2025 2024
Cash flow from operating activities
Net result 3,802 22,875 33,883 101,804
Adjustments for non-cash related items:
Depletion, depreciation and amortization 2,8 34,060 32,860 96,438 103,741
Income tax 6 3,030 8,257 13,876 29,473
Amortization of capitalized financing fees 5 538 524 1,586 1,534
Foreign currency exchange loss/(gain) 4,5 5,731 (5,360) (8,502) (1,743)
Interest income 4 (501) (4,112) (2,829) (14,646)
Interest expense 5 10,082 9,119 27,823 26,865
Unwinding of asset retirement obligation discount 5 4,229 3,680 12,301 10,939
Share-based costs 2,455 2,267 7,164 6,443
Changes in working capital (641) 14,213 17,689 (56,814)
Decommissioning costs paid 16 (1,739) (2,575) (4,157) (4,938)
Other payments 16 (646) – (1,474) (504)
Net income taxes refunded/(paid) (1,441) (3,206) (3,529) (2,929)
Interest received 810 3,669 3,444 11,948
Interest paid (16,867) (16,358) (33,273) (32,772)
Other 639 241 2,690 557
Net cash flow from operating activities 43,541 66,094 163,130 178,958
Cash flow used in investing activities
Investment in oil and gas properties
8 (80,128) (99,218) (276,939) (308,704)
Investment in other tangible fixed assets 8 (189) – (410) –
Net cash (outflow) from investing activities (80,317) (99,218) (277,349) (308,704)
Cash flow from financing activities
Proceeds from borrowings
15 26,576 – 26,576 –
Repayment of borrowings 15 (780) (586) (1,949) (2,600)
Repurchase of own shares 13 (21,560) (35,205) (100,264) (80,943)
Paid financing fees – – (686) –
Other payments (206) (217) (670) (689)
Dividend – – (16) –
Net cash (outflow) from financing activities 4,030 (36,008) (77,009) (84,232)
Change in cash and cash equivalents (32,746) (69,132) (191,228) (213,978)
Cash and cash equivalents at the beginning of the
period 78,886 368,797 246,593 517,074
Currency exchange difference in cash and cash
equivalents (1,479) (462) (10,704) (3,893)
Cash and cash equivalents at the end of the period 44,661 299,203 44,661 299,203
See accompanying notes to the interim condensed consolidated financial statements
===== SIDA 7 =====
7
Interim Condensed Consolidated Statement of Changes in Equity
For the nine month periods ended September 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 – 33,878 – – – – 33,878 5 33,883
Cash flow hedges – – – – 22,431 – 22,431 – 22,431
Currency translation difference – – 35,755 548 -329 – 35,974 5 35,979
Total comprehensive income – 33,878 35,755 548 22,102 – 92,283 10 92,293
Repurchase of own shares1 (100,264) – – – – – (100,264) – (100,264)
Dividend Distribution – – – – – – – (16) (16)
Share based costs – – – 7,164 – – 7,164 – 7,164
Share based payments2 – (8,198) – (9,006) – – (17,204) – (17,204)
Balance at September 30, 2025 40,909 901,632 (45,437) 16,798 8,964 (1,572) 921,294 149 921,443
1 See Note 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 – 101,788 – – – – 101,788 16 101,804
Cash flow hedges – – – – (17,591) – (17,591) – (17,591)
Currency translation difference – – (13,659) (2,057) (721) – (16,437) (2) (16,439)
Total comprehensive income – 101,788 (13,659) (2,057) (18,312) – 67,760 14 67,774
Repurchase of own shares1 (82,558) – – – – – (82,558) – (82,558)
Dividend distribution – – – – – – – (41) (41)
Share based costs – – – 6,443 – – 6,443 – 6,443
Share based payments2 – (21,740) – (6,131) – – (27,871) – (27,871)
Balance at September 30, 2024 160,803 875,538 (24,404) 17,093 13,032 1,786 1,043,848 158 1,044,006
1 See Note 13
2 The third instalment of IPC RSP 2021 awards, the second instalment of IPC RSP 2022 awards, the first instalment of IPC RSP 2023 awards and
the IPC PSP 2021 awards vested on 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 nine months ended September 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 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 November 4, 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 nine months ended September 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 nine months ended September 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 nine months ended September 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 September 30, 2025
USD Thousands Canada Malaysia France Other Total
Crude oil 154,454 15,581 11,870 – 181,905
NGLs 177 – – – 177
Gas 4,630 – – – 4,630
Net sales of oil and gas 159,261 15,581 11,870 – 186,712
Change in under/over lift position – – 1,585 – 1,585
Royalties (21,941) – (931) – (22,872)
Hedging settlement 6,587 – – – 6,587
Other operating revenue – – 197 88 285
Revenue 143,907 15,581 12,721 88 172,297
Operating costs (56,465) (10,908) (8,254) – (75,627)
Cost of blending (32,451) – – – (32,451)
Change in inventory position (379) 2,327 (253) – 1,695
Depletion and decommissioning costs (22,785) (6,504) (2,956) – (32,245)
Depreciation of other tangible fixed assets – (1,419) – – (1,419)
Exploration and business development costs – – – (184) (184)
Gross profit/(loss) 31,827 (923) 1,258 (96) 32,066
Three months ended September 30, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 157,123 17,876 15,939 – 190,938
NGLs 243 – – – 243
Gas 3,889 – – – 3,889
Net sales of oil and gas 161,255 17,876 15,939 – 195,070
Change in under/over lift position – – 1,289 – 1,289
Royalties (27,604) – (1,164) – (28,768)
Hedging settlement 5,366 – – – 5,366
Other operating revenue – – 216 27 243
Revenue 139,017 17,876 16,280 27 173,200
Operating costs (56,958) (9,140) (7,823) – (73,921)
Cost of blending (29,818) – – – (29,818)
Change in inventory position (330) 3,516 (431) – 2,755
Depletion and decommissioning costs (21,092) (6,285) (3,114) – (30,491)
Depreciation of other tangible fixed assets – (2,023) – – (2,023)
Exploration and business development costs – – – (197) (197)
Gross profit/(loss) 30,819 3,944 4,912 (170) 39,505
===== SIDA 10 =====
10
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
Nine months ended September 30, 2025
USD Thousands Canada Malaysia France Other Total
Crude oil 456,478 42,785 36,147 – 535,410
NGLs 535 – – – 535
Gas 26,004 – – – 26,004
Net sales of oil and gas 483,017 42,785 36,147 – 561,949
Change in under/over lift position – – 4,285 – 4,285
Royalties (65,614) – (2,503) – (68,117)
Hedging settlement 10,746 – – – 10,746
Other operating revenue – – 572 246 818
Revenue 428,149 42,785 38,501 246 509,681
Operating costs (159,256) (31,257) (24,789) – (215,302)
Cost of blending (103,446) – – – (103,446)
Change in inventory position (366) 5,869 (427) – 5,076
Depletion and decommissioning costs (65,421) (17,146) (8,015) – (90,582)
Depreciation of other tangible fixed assets – (4,797) – – (4,797)
Exploration and business development costs – – – (752) (752)
Gross profit/(loss) 99,660 (4,546) 5,270 (506) 99,878
Nine months ended September 30, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 517,757 75,770 49,909 – 643,436
NGLs 762 – – – 762
Gas 24,981 – – – 24,981
Net sales of oil and gas 543,500 75,770 49,909 – 669,179
Change in under/over lift position – – 6,420 – 6,420
Royalties (86,376) – (3,464) – (89,840)
Hedging settlement 11,928 – – – 11,928
Other operating revenue – – 670 302 972
Revenue 469,052 75,770 53,535 302 598,659
Operating costs (166,648) (23,385) (24,538) – (214,571)
Cost of blending (116,699) – – – (116,699)
Change in inventory position (287) 3,726 (279) – 3,160
Depletion and decommissioning costs (66,482) (20,208) (9,615) – (96,305)
Depreciation of other tangible fixed assets – (6,503) – – (6,503)
Exploration and business development costs – – – (344) (344)
Gross profit/(loss) 118,936 29,400 19,103 (42) 167,397
===== SIDA 11 =====
11
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
3. PRODUCTION COSTS
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2025 2024 2025 2024
Cost of operations 64,024 64,027 183,141 183,223
Tariff and transportation expenses 10,498 8,676 28,947 27,606
Direct production taxes 1,105 1,218 3,214 3,742
Operating costs 75,627 73,921 215,302 214,571
Cost of blending1 32,451 29,818 103,446 116,699
Change in inventory position (1,695) (2,755) (5,076) (3,160)
Total production costs 106,383 100,984 313,672 328,110
1 In Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. Cost of blending represents the contracted
purchase of diluent used for blending.
4. FINANCE INCOME
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2025 2024 2025 2024
Foreign exchange gain, net – 5,360 8,502 1,743
Interest income 501 4,112 2,829 14,646
Total finance income 501 9,472 11,331 16,389
5. FINANCE COSTS
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2025 2024 2025 2024
Foreign exchange loss, net 5,731 – – –
Interest expense 10,082 9,119 27,823 26,865
Unwinding of asset retirement obligation discount 4,229 3,680 12,301 10,939
Amortization of capitalized financing fees 538 524 1,586 1,534
Loan commitment fees 175 169 719 614
Currency hedge losses, net 521 – 8,039 –
Other financial costs 255 104 589 379
Total finance costs 21,531 13,596 51,057 40,331
6. INCOME TAX
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2025 2024 2025 2024
Current tax 97 373 (754) (6,718)
Deferred tax (3,127) (8,630) (13,122) (22,755)
Total tax expense (3,030) (8,257) (13,876) (29,473)
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 September 30, 2025 December 31, 2024
Unused tax loss carry forward 56,970 40,042
Derivative hedges 234 3,933
Other 6,298 10,302
Deferred tax assets 63,502 54,277
Accelerated allowances 177,654 145,358
Derivative hedges 2,785 –
Deferred tax liabilities 180,439 145,358
Deferred taxes, net (116,937) (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 3,529 – – 3,529
Currency translation adjustments 30 – – 30
Net book value September 30, 2025 4,039 – – 4,039
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 1,724,258 1,484,487
Other tangible fixed assets 11,866 16,425
Property, Plant and Equipment 1,736,124 1,500,912
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 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 229,467 39,161 4,782 273,410
Change in estimates (2,792) 2,200 – (592)
Currency translation adjustments 60,253 – 52,435 112,688
September 30, 2025 2,054,508 641,095 462,346 3,157,949
Accumulated depletion
January 1, 2025 (451,017) (530,315) (306,624) (1,287,956)
Depletion charge for the period (65,420) (17,146) (8,016) (90,582)
Currency translation adjustments (15,381) – (39,772) (55,153)
September 30, 2025 (531,818) (547,461) (354,412) (1,433,691)
Net book value September 30, 2025 1,522,690 93,634 107,934 1,724,258
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 nine months ended September 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 – 410 410
Disposals – (6) (6)
Currency translation adjustments – 739 739
September 30, 2025 204,853 10,967 215,820
Accumulated depreciation
January 1, 2025 (190,056) (8,196) (198,252)
Depreciation charge for the period (4,797) (303) (5,100)
Disposals – 6 6
Currency translation adjustments – (608) (608)
September 30, 2025 (194,853) (9,101) (203,954)
Net book value September 30, 2025 10,000 1,866 11,866
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, has been 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 and administrative expenses in the Statement of Operations.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
===== SIDA 15 =====
15
9. OTHER NON-CURRENT ASSETS
USD Thousands September 30, 2025 December 31, 2024
Financial assets 37,310 34,788
Intangible assets 14,695 13,877
52,005 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 respect of work commitments in Malaysia amounting to USD 4.0 million.
Intangible assets mainly represent carbon offsets purchased in Canada.
10. INVENTORIES
USD Thousands September 30, 2025 December 31, 2024
Hydrocarbon stocks 16,777 11,250
Well supplies and operational spares 8,407 8,823
25,184 20,073
11. TRADE AND OTHER RECEIVABLES
USD Thousands September 30, 2025 December 31, 2024
Trade receivables 62,338 94,265
Underlift 5,638 1,007
Joint operations debtors 2,342 1,432
Prepaid expenses and accrued income 13,418 12,346
Other 1,581 18,400
85,317 127,450
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 (7,822,595)
Balance at December 31, 2024 119,169,471
Cancellation of repurchased common shares (6,989,406)
Balance at September 30, 2025 112,180,065
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.
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.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
===== SIDA 16 =====
16
As at December 31, 2024, IPC had a total of 119,169,471 common shares issued and outstanding, of which IPC held 110,156
common shares in treasury.
During the first nine months of 2025, IPC purchased 6,641,970 common shares under the NCIB and 261,818 common shares
under certain other exemptions in Canada.
As at September 30, 2025, following the cancellation during the first nine months of 2025 of 6,989,406 common shares
repurchased, IPC had a total of 112,180,065 common shares issued and outstanding, of which IPC held 24,538 common shares in
treasury. IPC cancelled these shares held in treasury in October 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.
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
September 30
Nine months ended
September 30
2025 2024 2025 2024
Net result attributable to shareholders of the Parent Company, USD 3,801,000 22,874,360 33,878,000 101,788,043
Weighted average number of shares for the period 113,341,626 123,244,183 117,250,357 125,197,549
Earnings per share, USD 0.03 0.19 0.29 0.81
Weighted average diluted number of shares for the period 115,071,207 125,165,037 118,979,939 127,118,402
Earnings per share fully diluted, USD 0.03 0.18 0.28 0.80
15. FINANCIAL LIABILITIES
USD Thousands September 30, 2025 December 31, 2024
Current bank loans 2,907 3,402
Non current bank loans 26,576 1,719
Bonds 445,765 443,407
Capitalized financing fees (2,269) (3,545)
472,979 444,983
As at September 30, 2025, IPC had USD 450 million of senior unsecured bonds outstanding, maturing in February 2027 with a
fixed coupon rate of 7.25% per annum, 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.
On September 25, 2025, IPC announced the placement of USD 450 million of new senior unsecured bonds, maturing in October
2030 with a fixed coupon rate of 7.50% per annum, payable in semi-annual instalments in April and October. The new bonds were
issued in October 2025, with the proceeds being used to fully redeem and cancel the previous bonds. IPC exercised its call option
to redeem the previous bonds at a price equal to 102.18% of the nominal amount, plus accrued and unpaid interest. The expected
cash refinancing costs, which include the call option costs of the senior unsecured bonds, and the related transaction costs, to be
incurred in Q4 2025, are estimated at approximately USD 18 million.
The bond repayment obligations as at September 30, 2025, are classified as non-current as there are no mandatory repayments
within the next twelve months.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
===== SIDA 17 =====
17
In addition, as at September 30, 2025, the Group had a senior secured revolving credit facility of CAD 250 million (the “Canadian
RCF”) in connection with its oil and gas assets in Canada, with a maturity date in May 2027. As at September 30, 2025, CAD 37
million (USD 27 million) was drawn under the Canadian RCF . As at September 30, 2025, the Group also had a letter of credit facility
in Canada (the “LC Facility”) to cover operational letters of credit. As at September 30, 2025, operational letters of credit in an
aggregate of CAD 33.7 million have been issued under the LC Facility, of which CAD 24.5 million relates to a third party pipeline
construction agreement for the Blackrod Phase 1 Development project which is expected to be released when the pipeline
become operational.
As at September 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 September 30, 2025 was USD 2.9 million (EUR 2.5 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 September 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 – – – 732 732
Unwinding of asset retirement obligation discount 12,301 – – – 12,301
Payments (4,157) (587) – (887) (5,631)
Change in estimates (592) – – – (592)
Reclassification1 764 – – – 764
Currency translation adjustments 10,510 98 – 107 10,715
September 30, 2025 286,616 1,190 3,685 2,024 293,515
Non-current 280,188 596 3,685 2,024 286,493
Current 6,428 594 – – 7,022
Total 286,616 1,190 3,685 2,024 293,515
1 The reclassification of the asset retirement obligation related to the 2025 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 9).
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).
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 30, 2025 and 2024, UNAUDITED
===== SIDA 18 =====
18
The farm-in obligation relates to future payments for historic costs on the Bertam field in Malaysia payable for every 1 MMb oe
gross that the field produces above 10 MMboe gross and is capped at cumulative production of 27.5 MMboe gross.
In calculating the present value of the asset retirement obligation provision, a blended rate of 6% (2024: 6%) per annum was used,
based on a credit risk adjusted rate.
17. TRADE AND OTHER PAYABLES
USD Thousands September 30, 2025 December 31, 2024
Trade payables 32,446 42,634
Joint operations creditors 13,285 11,671
Accrued expenses 103,239 119,316
Other 8,209 2,750
157,179 176,371
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:
September 30, 2025
USD Thousands
Total
Financial assets
at amortized
cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Other assets1 37,310 37,310 – –
Derivative instruments 13,843 – – 13,843
Joint operation debtors 2,342 2,342 – –
Other current receivables2 73,029 67,391 5,638 –
Cash and cash equivalents 44,661 44,661 – –
Financial assets 171,185 151,704 5,638 13,843
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
September 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 470,072 470,072 – –
Current financial liabilities 2,907 2,907 – –
Derivative instruments 2,097 – – 2,097
Joint operation creditors 13,285 13,285 – –
Other current liabilities 144,003 144,003 – –
Financial liabilities 632,364 630,267 – 2,097
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 nine months ended September 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:
September 30, 2025
USD Thousands Level 1 Level 2 Level 3
Other current receivables 5,638 – –
Derivative instruments – current – 12,069 –
Derivative instruments – non-current – – 1,774
Financial assets 5,638 12,069 1,774
Derivative instruments – current – 1,691 406
Derivative instruments – non-current – – –
Financial liabilities – 1,691 406
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 September 30, 2025 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
October 1, 2025 - December 31, 2025 11,700 WTI/WCS Differential USD -14.16/bbl
October 1, 2025 - December 31, 2025 10,000 WTI Sale Swap USD 71.30/bbl
October 1, 2025 - December 31, 2025 4,000 WTI Collar USD 65.00/bbl (Put)
USD 75.45/bbl (Call)
October 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 nine months ended September 30, 2025 and 2024, UNAUDITED
===== SIDA 20 =====
20
The Group had gas price sale financial hedges outstanding as at September 30, 2025 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
October 1, 2025 - October 31, 2025 20,000 AECO Gas Swap CAD 2.25/GJ
October 1, 2025 - December 31, 2025 10,000 AECO Gas Swap CAD 2.50/GJ
April 1, 2026 - October 31, 2026 10,000 AECO Gas Swap CAD 2.65/GJ
The Group had electricity financial hedges outstanding as at September 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 97.5 million for the period October 2025 to December 2025 at an average rate of CAD 1.36 (sell USD);
(ii) a total EUR 6.75 million for the period October 2025 to December 2025 at an average rate of EUR 1.08 (sell USD);
(iii) a total MYR 30 million for the period October 2025 to December 2025 at an average rate of MYR 4.38 (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 September 30, 2025:
CAD Millions 2025 2026 2027 2028 2029 Thereafter
Transportation service1 9.9 59.3 91.6 99.1 103.1 1,488.7
Power2 3.6 12.4 12.4 9.8 – –
Total commitments 13.5 71.7 104.0 108.9 103.1 1,488.7
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2047.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from October 1, 2025 - December
31, 2028, an additional 5MWh at a weighted average price of CAD 58.31/MWh from October 1, 2025 to December 31, 2027, and an additional
5MWh at a weighted average price of CAD 46.85/MWh from October 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 nine months of 2025, the Group has not entered into material transactions with related parties.
21. SUBSEQUENT EVENTS
In October 2025, the Group entered into the following oil price sale financial hedges:
Period Volume (barrels per day) Type Average Pricing
January 1, 2026 - December 31, 2026 5,000 WTI/WCS Differential USD -12.50/bbl
In October 2025, IPC completed the issuance of USD 450 million of new senior unsecured bonds maturing in October 2030 and
fully redeemed the previous bonds, refer to Note 15 for further details.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and nine months ended September 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 =====
Q3
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three and nine months ended September 30, 2025
===== SIDA 23 =====
Management’s Discussion and Analysis
For the three and nine months ended September 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 nine months ended September 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 November 4, 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 nine months ended September 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:
September 30, 2025 September 30, 2024 December 31, 2024
Average Period end Average Period end Average Year end
1 EUR equals USD 1.1180 1.1741 1.0870 1.1196 1.0821 1.0389
1 USD equals CAD 1.3993 1.3922 1.3602 1.3516 1.3698 1.4388
1 USD equals MYR 4.3265 4.2085 4.6352 4.1235 4.5759 4.4715
3
===== SIDA 25 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
HIGHLIGHTS
Q3 2025 Business Highlights
• Average net production of approximately 45,900 boepd for Q3 2025, above guidance (53% heavy crude oil, 14% light and
medium crude oil and 33% natural gas).(1)
• Continued progress of Blackrod Phase 1 development activity with Central Processing Facility (CPF) construction almost
complete, progressive commissioning advancing, and first steam and first oil forecast a quarter earlier than originally guided.
• At Onion Lake Thermal, Canada, the final two of four planned production infill wells and the final Pad L sustaining well pair
were successfully brought online.
• Announced the refinancing of IPC’s MUSD 450 unsecured bonds, extending the maturity to October 2030.
• 1.1 million IPC common shares purchased and cancelled during Q3 2025 under the normal course issuer bid (NCIB),
completing the full 2024/2025 NCIB of approximately 7.5 million IPC common shares.
• IPC plans to seek Toronto Stock Exchange (TSX) approval for the renewal of the NCIB in December 2025.
Q3 2025 Financial Highlights
• Operating costs per boe of USD 17.9 for Q3 2025, marginally below guidance. (3)
• Operating cash flow (OCF) generation of MUSD 66 for Q3 2025, in line with guidance. (3)
• Capital and decommissioning expenditures of MUSD 82 for Q3 2025, in line with guidance.
• Free cash flow (FCF) generation for Q3 2025 amounted to MUSD -23 (MUSD 36 pre-Blackrod capital expenditures). (3)
• Gross cash of MUSD 45 and net debt of MUSD 435 as at September 30, 2025. (3)
• Net result of MUSD 4 for Q3 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 guidance range tightened to between MUSD 245 and 255 (assuming Brent USD 55 to 65 per barrel for
the remainder of 2025) from previous guidance of between MUSD 245 and 260 (which assumed Brent USD 60 to 75 per
barrel for the second half of 2025).
(3)(4)
• Full year 2025 capital and decommissioning expenditures guidance revised from MUSD 320 to MUSD 340 (including MUSD
250 for the Blackrod asset), following the advancement of Blackrod Phase 1 drilling activity into Q4 2025 .
• Full year 2025 FCF revised guidance estimated at between MUSD -170 and -160 (assuming Brent USD 55 to 65 per barrel for
the remainder of 2025) from previous guidance of between MUSD -135 and -120 (which assumed Brent USD 60 to 75 per
barrel for the second half of 2025).
(3)(4)
Three months ended
September 30
Nine months ended
September 30
USD Thousands 2025 2024 2025 2024
Revenue 172,297 173,200 509,681 598,659
Gross profit 32,066 39,505 99,878 167,397
Net result 3,802 22,875 33,883 101,804
Operating cash flow(3) 66,102 72,589 195,765 263,831
Free cash flow(3) (23,083) (38,269) (124,507) (74,021)
EBITDA(3) 62,106 68,313 184,571 259,304
Net cash/(debt)(3) (434,822) (157,228) (434,822) (157,228)
4
===== SIDA 26 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
OPERATIONS REVIEW
Business Overview
During the third quarter of 2025, the average Brent price was approximately USD 69 per barrel, as compared to approximately
USD 68 per barrel for the second quarter of 2025. The Brent price remained relatively stable during the third quarter, with some
downward pressure on prices post-quarter due to concerns over market oversupply and concerns around global trade between
China and the US. Global observed petroleum inventories have increased, mainly driven by OPEC’s unwinding of voluntary
production cuts, long-dated non-OPEC supply growth projects coming on-stream, and sanctioned countries’ production output
being high relative to historical standard. Given the uncertainty and low-price strip outlook, it is unlikely near-term incremental
upstream growth investment will be pursued by industry. Global oil demand is expected to be an all-time high in 2025 and is
predicted to continue to rise in 2026.
Alongside the more constructive factors for stronger oil prices in the medium to longer term, the need to alleviate poverty in
emerging markets coupled with meeting the infrastructure build-out requirements for technological advancements, namely with
data centres and AI, places a major emphasis on the need for metals and high-density forms of energy. The precious and base
metal supply needs will go hand-in-hand with a reliance on oil and its irreplaceable byproducts in order to develop and transport
more mined material. While uncertainty exists with respect to forecasting oil prices, IPC has strongly positioned itself with forecast
sustained higher production levels in the years ahead which should positively coincide with a higher pricing cycle at a time likely
not too far into the future.
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.
The WTI to Western Canadian Select (WCS) price differential during the third quarter averaged less than USD 11 per barrel. The
WTI to WCS differential continues to benefit from the TMX pipeline expansion, driving up competitive tension for Canadian oil
and increased buying from Asia. The current and outlook of the WTI to WCS differential remains tight with excess egress capacity
relative to the supply in the Western Canadian Sedimentary Basin (WCSB). There are currently no tariffs on Canadian crude oil
exports to the United States, which remain covered by the US Mexico Canada 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. For 2026, IPC
implemented WTI to WCS differential hedges in October 2025 for approximately 5,000 barrels per day at USD -12.50 per barrel.
The average Canadian gas benchmark price, AECO, was CAD 0.6 per Mcf for the third quarter of 2025 and IPC achieved an
average realized price of CAD 0.8 per Mcf during the quarter. WCSB gas inventory levels remain elevated above the historical
average. There is an expectation for storage levels to draw during the winter period and further supported by the ramp up of the
LNG Canada project in 2026 which should drive higher natural gas prices. Approximately 50% of our net long gas exposure was
hedged at CAD 2.4 per Mcf to end October 2025, with around 15% of net long gas exposure hedged for November and December
at CAD 2.6 per Mcf. For 2026, IPC implemented hedges in the third quarter of 2025 for approximately 9,600 Mcf per day at CAD
2.80 per Mcf from April to October 2026.
Third Quarter 2025 Highlights and Full Year 2025 Guidance
During the third quarter of 2025, our portfolio delivered average net production of 45,900 boepd, ahead of guidance. The strong
performance in the quarter was supported by the sustaining capital investment activities undertaken at the Onion Lake Thermal
asset and at the Bertam field in Malaysia. 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 third quarter of 2025 was USD 17.9, 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 third quarter of 2025 was MUSD 66. Full year 2025 OCF guidance is tightened to
MUSD 245 to 255 (assuming Brent USD 55 to 65 per barrel for the remainder of 2025).
(3)(4)
Capital and decommissioning expenditure for the third quarter of 2025 was MUSD 82, in line with guidance. Full year 2025 capital
and decommissioning expenditure is revised to MUSD 340, from MUSD 320, mainly due to the acceleration of the drilling of the
final well pad for the Blackrod Phase 1 project into the fourth quarter of 2025.
Free cash flow (FCF) generation was MUSD -23 (MUSD 36 pre-Blackrod capital expenditures) during the third quarter of 2025. Full
year 2025 FCF guidance is revised to MUSD -170 to -160 (assuming Brent USD 55 to 65 per barrel for the remainder of 2025) after
taking into account MUSD 340 of forecast full year 2025 capital expenditures (including MUSD 250 relating to the Blackrod asset)
and costs incurred from the bond refinancing.
(3)(4)
As at September 30, 2025, IPC’s net debt position increased to MUSD 435, from a net debt position of MUSD 375 as at June 30,
2025, mainly driven by the funding of capital expenditures and the share repurchase program (NCIB). Gross cash as at September
30, 2025 amounted to MUSD 45.
5
===== SIDA 27 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
In the third quarter of 2025, IPC announced that it had taken advantage of favourable debt capital market conditions to successfully
refinance its MUSD 450 of unsecured bonds. The new bonds issued in October 2025 have a maturity in October 2030, with a
coupon of 7.5% per annum. IPC believes that this is a great outcome since the US 5-year swap rates increased by almost 2%
compared to IPC’s inaugural bond issuance in the first quarter of 2022 while the coupon only increased by 0.25% to 7.5%. In
addition, IPC continues to have access to a Canadian revolving credit facility of MCAD 250 (approximately MUSD 180), with MCAD
37 (approximately MUSD 27) drawn under that facility as at September 30, 2025. 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. Since
the Phase 1 project sanction to the end of the third quarter of 2025, capital expenditures of MUSD 785 have been incurred, or
approximately 92% of the MUSD 850 growth capital guidance to first oil.
(1)
All major work activities continued to advance at the Blackrod asset during the third quarter. Construction activities are nearing
completion and progressive commissioning of the CPF is ahead of schedule. While full commissioning works remain to be
completed, IPC is now confident that first steam at the project should occur before the end of 2025 with first oil to follow in the
third quarter of 2026, a quarter earlier than originally guided. As a result of an earlier expected startup for the Phase 1 project,
drilling of the final well pad is planned to be started in the fourth quarter of 2025 from early 2026.
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 as needed.
(3)
Stakeholder Returns: Normal Course Issuer Bid
In the fourth quarter of 2024, IPC announced the implementation of the 2024/2025 NCIB to purchase 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 and over 6.6 million common shares during the first
nine months of 2025 under the NCIB, as well as a further 0.3 million common shares under other exemptions in Canada. The
average price of common shares repurchased under the 2024/2025 NCIB during the first nine months of 2025 was around SEK
144 / CAD 20 per share.
IPC completed the 2024/2025 NCIB by the end of September 2025, purchasing and cancelling approximately 7.5 million common
shares. This resulted in the cancellation of 6.2% of the common shares outstanding as at the beginning of December 2024.
As at September 30, 2025, IPC had a total of 112,180,065 common shares issued and outstanding, of which IPC held 24,538
common shares in treasury. As at November 4, 2025, IPC had a total of 112,155,527 common shares issued and outstanding and
IPC held no common shares in treasury.
The IPC Board of Directors has approved, subject to acceptance by the Toronto Stock Exchange (TSX), the renewal of IPC’s NCIB
for a further twelve months from December 2025 to early December 2026. We expect that the 2025/2026 NCIB will permit IPC to
purchase on the TSX and/or Nasdaq Stockholm, and cancel, up to a further approximately 6.5 million common shares, representing
approximately 5.8% of the total current outstanding common shares (or 10% of IPC’s “public float” under applicable TSX rules).
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.
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 55 to 65 per barrel assume Brent to WTI and WTI to WCS differentials of USD 3 and
10 per barrel, respectively, for the remainder of 2025. OCF and FCF forecasts assume gas price on average of CAD 1.75 per
Mcf for the fourth quarter of 2025.
6
===== SIDA 28 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
Operations Overview
Q3 2025 Overview
In Q3 2025, IPC continued to successfully demonstrate its commitment to operational excellence, delivering production
performance and operating 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 2P 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 Q3 2025 was ahead of IPC’s high end CMD guidance at 45,900 boepd. In Canada, strong
operational performance at the major oil and gas assets has been supplemented by recent production infill well drilling at Onion
Lake Thermal. Stable performance continued at our Malaysian and French assets.
With continued strong operational delivery during the third 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 for 2025 within the guidance range of 43,000 to
45,000 boepd.
The production during Q3 2025 with comparatives is summarized below:
Production
in Mboepd
Three months ended
September 30
Nine months ended
September 30
Year ended
December 31
2025 2024 2025 2024 2024
Crude oil
Canada – Northern Assets 15.8 12.7 14.5 14.0 14.2
Canada – Southern Assets 9.9 10.9 10.4 11.1 11.1
Malaysia 3.2 3.7 2.8 4.0 3.8
France 2.1 2.4 2.1 2.5 2.4
Total crude oil production 31.0 29.7 29.8 31.6 31.5
Gas
Canada – Northern Assets 0.5 0.4 0.4 0.4 0.5
Canada – Southern Assets 14.4 14.9 14.4 15.4 15.4
Total gas production 14.9 15.3 14.8 15.8 15.9
Total production 45.9 45.0 44.6 47.4 47.4
Quantity in MMboe 4.22 4.14 12.19 12.98 17.34
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
CANADA
Production
in Mboepd
Working
Interest
(WI)
Three months ended
September 30
Nine months ended
September 30
Year ended
December 31
2025 2024 2025 2024 2024
- Oil Onion Lake Thermal 100% 13.1 10.7 12.0 12.4 12.3
- Oil Suffield Area 100% 8.7 9.2 9.0 9.7 9.7
- Oil Other 50-100% 3.9 3.7 3.9 3.0 3.3
- Gas ~100% 14.9 15.3 14.8 15.8 15.9
Canada 40.6 38.9 39.7 40.9 41.2
7
===== SIDA 29 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
Production
Net production from IPC’s assets in Canada during Q3 2025 was ahead of guidance at 40,600 boepd with continued strong
operational performance at the major oil and gas producing assets. At Onion Lake Thermal, recent production infill well drilling
contributed to strong production rates during the quarter. At Mooney, the Phase 2 polymer flood project continues to deliver ahead
of expectations.
Organic Growth and Capital Projects
The Blackrod Phase 1 development project in Canada continues to progress, with construction almost complete and progressive
commissioning of the central processing facility (CPF) advancing ahead of schedule. As at the end of Q3 2025, acceleration of
construction and commissioning activity has supported early delivery of the first commercial fuel gas to the CPF site. Both site
power generators have been commissioned and the Blackrod CPF is energized in preparation for final first steam commissioning
activities. On the back of the latest progress, IPC is confident that first steam and subsequently first oil should be achieved a
quarter earlier than our original guidance. Based on this progress, IPC has decided to accelerate the drilling of the final production
well pad into Q4 2025 from the previously planned commencement in early 2026.
At Onion Lake Thermal, the four 2025 drilled production infill wells and the ninth Pad L sustaining well pair are online with
production performance ahead of expectations.
MALAYSIA
Production
in Mboepd WI
Three months ended
September 30
Nine months ended
September 30
Year ended
December 31
2025 2024 2025 2024 2024
Bertam 100% 3.2 3.7 2.8 4.0 3.8
Production
Net production at Bertam in Malaysia in Q3 2025 was in line with guidance at 3,200 boepd. Planned maintenance shutdown
activity that commenced towards the end of Q3 has been completed on time and in line with budget in early Q4 2025.
Organic Growth and Capital Projects
In Malaysia, the planned infill well and well maintenance activity was completed early in Q3 2025. Wells A21 and A15 were
brought on to production in late July with overall performance in line with expectations.
FRANCE
Production
in Mboepd WI
Three months ended
September 30
Nine months ended
September 30
Year ended
December 31
2025 2024 2025 2024 2024
France
- Paris Basin 100%1 1.8 2.1 1.8 2.2 2.1
- Aquitaine 50% 0.3 0.3 0.3 0.3 0.3
2.1 2.4 2.1 2.5 2.4
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q3 2025 was in line with guidance at 2,100 boepd with stable performance across all the
producing fields.
Organic Growth
In France, field development studies continued in Q3 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 nine months ended September 30, 2025
FINANCIAL REVIEW
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q3-25 Q2-25 Q1-25 Q4-24 Q3-24 Q2-24 Q1-24 Q4-23
Revenue 172,297 158,892 178,492 199,124 173,200 219,040 206,419 198,460
Gross profit 32,066 23,663 44,149 42,774 39,505 72,708 55,184 39,955
Net result 3,802 13,850 16,231 415 22,875 45,210 33,719 29,710
Earnings per share – USD 0.03 0.12 0.14 0.00 0.19 0.36 0.27 0.23
Earnings per share fully
diluted – USD 0.03 0.12 0.13 0.00 0.18 0.36 0.26 0.22
Operating cash flow1 66,102 54,873 74,790 78,158 72,589 101,941 89,301 73,634
Free cash flow1 (23,083) (58,252) (43,172) (61,476) (38,269) 7,559 (43,311) (64,688)
EBITDA1 62,106 51,519 70,946 76,184 68,313 103,971 87,020 66,284
Net cash/(debt) at period end1 (434,822) (374,977) (314,255) (208,528) (157,228) (88,220) (60,572) 58,043
1 See definition on page 18 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands September 30, 2025 December 31, 2024
Non-current assets 1,798,672 1,554,833
Current assets 170,703 398,849
Total assets 1,969,375 1,953,682
Total non-current liabilities 877,741 806,134
Current liabilities 170,191 208,078
Total liabilities 1,047,932 1,014,212
Net assets 921,443 939,470
Working capital (including cash) 512 190,771
9
===== SIDA 31 =====
Management’s Discussion and Analysis
For the three and nine months ended September 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 area assets). This is consistent with the internal reporting provided to the CEO,
who is the chief operating decision maker. The following tables present certain segment information.
Three months ended – September 30, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 99,686 54,768 15,581 11,870 – 181,905
NGLs – 177 – – – 177
Gas 25 4,605 – – – 4,630
Net sales of oil and gas 99,711 59,550 15,581 11,870 – 186,712
Change in under/over lift position – – – 1,585 – 1,585
Royalties (14,269) (7,672) – (931) – (22,872)
Hedging settlement 1,886 4,701 – – – 6,587
Other operating revenue – – – 197 88 285
Revenue 87,328 56,579 15,581 12,721 88 172,297
Operating costs (20,707) (33,758) (10,908) (8,254) – (75,627)
Cost of blending (27,588) (4,863) – – – (32,451)
Change in inventory position (26) (353) 2,327 (253) – 1,695
Depletion (10,360) (12,425) (6,504) (2,956) – (32,245)
Depreciation of other assets – – (1,419) – – (1,419)
Exploration and business
development costs – – – – (184) (184)
Gross profit/(loss) 26,647 5,180 (923) 1,258 (96) 32,066
Three months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 88,579 68,544 17,876 15,939 – 190,938
NGLs – 243 – – – 243
Gas 26 3,863 – – – 3,889
Net sales of oil and gas 88,605 72,650 17,876 15,939 – 195,070
Change in under/over lift position – – – 1,289 – 1,289
Royalties (15,693) (11,911) – (1,164) – (28,768)
Hedging settlement 2,934 2,432 – – – 5,366
Other operating revenue – – – 216 27 243
Revenue 75,846 63,171 17,876 16,280 27 173,200
Operating costs (20,546) (36,412) (9,140) (7,823) – (73,921)
Cost of blending (24,113) (5,705) – – – (29,818)
Change in inventory position 369 (699) 3,516 (431) – 2,755
Depletion (8,204) (12,888) (6,285) (3,114) – (30,491)
Depreciation of other assets – – (2,023) – – (2,023)
Exploration and business
development costs – – – – (197) (197)
Gross profit/(loss) 23,352 7,467 3,944 4,912 (170) 39,505
10
===== SIDA 32 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
Nine months ended – September 30, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 283,855 172,623 42,785 36,147 – 535,410
NGLs – 535 – – – 535
Gas 204 25,800 – – – 26,004
Net sales of oil and gas 284,059 198,958 42,785 36,147 – 561,949
Change in under/over lift position – – – 4,285 – 4,285
Royalties (39,321) (26,293) – (2,503) – (68,117)
Hedging settlement 3,279 7,467 – – – 10,746
Other operating revenue – – – 572 246 818
Revenue 248,017 180,132 42,785 38,501 246 509,681
Operating costs (61,673) (97,583) (31,257) (24,789) – (215,302)
Cost of blending (87,265) (16,181) – – – (103,446)
Change in inventory position 143 (509) 5,869 (427) – 5,076
Depletion (28,042) (37,379) (17,146) (8,015) – (90,582)
Depreciation of other assets – – (4,797) – – (4,797)
Exploration and business
development costs – – – – (752) (752)
Gross profit/(loss) 71,180 28,480 (4,546) 5,270 (506) 99,878
Nine months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 308,206 209,551 75,770 49,909 – 643,436
NGLs – 762 – – – 762
Gas 195 24,786 – – – 24,981
Net sales of oil and gas 308,401 235,099 75,770 49,909 – 669,179
Change in under/over lift position – – – 6,420 – 6,420
Royalties (53,565) (32,811) – (3,464) – (89,840)
Hedging settlement 6,666 5,262 – – – 11,928
Other operating revenue – – – 670 302 972
Revenue 261,502 207,550 75,770 53,535 302 598,659
Operating costs (60,464) (106,184) (23,385) (24,538) – (214,571)
Cost of blending (97,283) (19,416) – – – (116,699)
Change in inventory position 737 (1,024) 3,726 (279) – 3,160
Depletion (27,413) (39,069) (20,208) (9,615) – (96,305)
Depreciation of other assets – – (6,503) – – (6,503)
Exploration and business
development costs – – – – (344) (344)
Gross profit/(loss) 77,079 41,857 29,400 19,103 (42) 167,397
11
===== SIDA 33 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
Three and nine months ended September 30, 2025, Review
Revenue
Revenue amounted to USD 172,297 thousand for Q3 2025 compared to USD 173,200 thousand for Q3 2024 and USD 509,681
thousand for the first nine months of 2025 compared to the USD 598,659 thousand for the first nine months of 2024, is analyzed
as follows:
USD Thousands
Three months ended
September 30
Nine months ended
September 30
2025 2024 2025 2024
Crude oil sales 181,905 190,938 535,410 643,436
Gas and NGL sales 4,807 4,132 26,539 25,743
Change in under/overlift position 1,585 1,289 4,285 6,420
Royalties (22,872) (28,768) (68,117) (89,840)
Hedging settlement 6,587 5,366 10,746 11,928
Other operating revenue 285 243 818 972
Revenue 172,297 173,200 509,681 598,659
The main components of revenue for the three and nine months ended September 30, 2025 and September 30, 2024,
respectively, are detailed below:
Crude oil sales
Three months ended – September 30, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 99,686 54,768 15,581 11,870 181,905
- Quantity sold in bbls 1,849,991 993,748 209,107 170,751 3,223,597
- Average price realized USD per bbl 53.88 55.11 74.51 69.52 56.43
Three months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 88,579 68,544 17,876 15,939 190,938
- Quantity sold in bbls 1,446,627 1,107,248 221,082 198,101 2,973,058
- Average price realized USD per bbl 61.23 61.90 80.86 80.46 64.22
Crude oil revenue was 5% lower in Q3 2025 compared to Q3 2024 due to higher sales volumes offset by lower prices. Canadian-
Northern Assets sales volumes are 28% higher in Q3 2025 compared to Q3 2024 as a result of sustaining capital investment
activities undertaken at Onion Lake Thermal.
The Suffield area assets and Onion Lake Thermal crude oil in Canada is blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada.
The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q3 2025, WTI averaged USD 65 per bbl compared to USD 75 per bbl for Q3 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 Q3 2025 and one cargo lifting in Q3 2024. Produced unsold oil barrels from Bertam at the end of Q3 2025 amounted to
188,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 69 per bbl for
Q3 2025 compared to USD 80 per bbl for the comparative period in 2024.
12
===== SIDA 34 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
Nine months ended – September, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 283,855 172,623 42,785 36,147 535,410
- Quantity sold in bbls 5,153,175 3,086,686 580,067 507,167 9,327,095
- Average price realized USD per bbl 55.08 55.93 73.76 71.27 57.40
Nine months ended – September, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 308,206 209,551 75,770 49,909 643,436
- Quantity sold in bbls 5,012,498 3,353,780 845,411 602,713 9,814,402
- Average price realized USD per bbl 61.49 62.48 89.63 82.81 65.56
The Suffield area assets and Onion Lake crude oil in Canada are blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada.
Crude oil revenue was lower by 17% during the first nine months of 2025 compared to the first nine months of 2024 due to oil
prices lower by 12% and production by 5%.
The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. For the first nine months of 2025,
WTI averaged USD 67 per bbl compared to USD 77 per bbl for the comparative period and the average discount to WCS used in
our pricing formula was USD 11 per bbl compared to USD 15 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 71per bbl for the first nine months of 2025 compared to USD 83 per bbl for the comparative period.
Gas and NGL sales
Three months ended – September 30, 2025
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 25 4,782 4,807
- Quantity sold in Mcf 69,170 7,404,566 7,473,736
- Average price realized USD per Mcf 0.37 0.65 0.64
Three months ended – September 30, 2024
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 26 4,106 4,132
- Quantity sold in Mcf 74,249 7,335,019 7,409,268
- Average price realized USD per Mcf 0.35 0.56 0.56
Gas and NGL sales revenue was 16% higher for the Q3 2025 compared to Q3 2024 mainly due to the higher achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For Q3 2025, IPC realized an average price of CAD 0.84 per
Mcf compared to AECO average pricing of CAD 0.62 per Mcf.
13
===== SIDA 35 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
Nine months ended – September 30, 2025
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 203 26,336 26,539
- Quantity sold in Mcf 212,242 21,611,998 21,824,240
- Average price realized USD per Mcf 0.96 1.22 1.22
Nine months ended – September 30, 2024
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 195 25,548 25,743
- Quantity sold in Mcf 208,107 22,810,152 23,018,259
- Average price realized USD per Mcf 0.94 1.12 1.12
Gas and NGL sales revenue was 3% higher for the first nine months of 2025 compared to the first nine 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 nine months of 2025, IPC realized an average price
of CAD 1.67 per Mcf compared to AECO average pricing of CAD 1.45 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 nine months of 2025 amounted to a gain of USD 10,746 thousand and consisted of
a gain of USD 5,628 thousand on the oil contracts and a gain of USD 5,118 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 106,383 thousand for Q3 2025 compared to USD 100,984
thousand for Q3 2024 and USD 313,672 thousand for the first nine months of 2025 compared to USD 328,110 thousand for the
first nine months of 2024, and is analyzed as follows:
Three months ended – September 30, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 22,707 33,758 10,908 8,254 – 75,627
USD/boe2 15.16 15.10 37.44 41.54 n/a 17.91
Cost of blending 27,588 4,863 – – – 32,451
Change in inventory position 26 353 (2,327) 253 – (1,695)
Production costs 50,321 38,974 8,581 8,507 – 106,383
Three months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 20,546 36,412 13,235 7,823 (4,095) 73,921
USD/boe2 17.07 15.35 39.27 34.99 n/a 17.87
Cost of blending 24,113 5,705 – – – 29,818
Change in inventory position (369) 699 (3,516) 431 – (2,755)
Production costs 44,290 42,816 9,719 8,254 (4,095) 100,984
14
===== SIDA 36 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
Nine months ended – September 30, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 61,673 97,583 34,785 24,789 (3,528) 215,302
USD/boe2 15.15 14.12 45.28 42.33 n/a 17.66
Cost of blending 87,265 16,181 – – – 103,446
Change in inventory position (143) 509 (5,869) 427 – (5,076)
Production costs 148,795 114,273 28,916 25,216 (3,528) 313,672
Nine months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 60,464 106,184 35,670 24,538 (12,285) 214,571
USD/boe2 15.28 14.65 32.92 35.65 n/a 16.53
Cost of blending 97,283 19,416 – – – 116,699
Change in inventory position (737) 1,024 (3,726) 279 – (3,160)
Production costs 157,010 126,624 31,944 24,817 (12,285) 328,110
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.
3 Included in the Malaysia operating costs is the lease cost for the FPSO Bertam which is owned by the Group. Other represents the FPSO Bertam
lease fee self-to-self payment elimination. Netting the self-to-self elimination against the operating costs in Malaysia reduces the operating costs
per boe for Malaysia to USD 37.44 for Q3 2025 and USD 27.12 for the comparative period and USD 40.69 and USD 21.58 for the nine months
ended September 30, 2025, and September 30, 2024, respectively
Operating costs
Operating costs amounted to USD 75,627 thousand for Q3 2025 compared to USD 73,921 thousand for Q3 2024 and USD
215,302 thousand for the first nine months of 2025 compared to USD 214,571 thousand for the first nine months of 2024.
Operating costs per boe amounted to USD 17.91 per boe in Q3 2025 marginally below the guidance for the quarter and compared
with USD 17.87 per boe in Q3 2024.
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 32,451 thousand for Q3 2025 compared to USD 29,818 thousand for Q3 2024 and USD
103,446 thousand for the first nine months of 2025 compared to USD 116,699 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 Q3 2025, IPC had crude entitlement of 188,000 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 32,245 thousand for Q3 2025 compared to USD 30,491 thousand
for Q3 2024 and USD 90,582 thousand for the first nine months of 2025 compared to USD 96,305 thousand for the first nine
months of 2024.
15
===== SIDA 37 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
The depletion charge is analyzed in the following tables:
Three months ended – September 30, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 10,360 12,425 6,504 2,956 32,245
USD per boe 6.92 5.56 22.32 14.89 7.64
Three months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 8,204 12,888 6,285 3,114 30,491
USD per boe 6.82 5.43 18.65 13.93 7.37
Nine months ended – September 30, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands1 28,042 37,379 17,146 8,015 90,582
USD per boe2 6.89 5.52 22.32 13.69 7.43
Nine months ended – September 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands1 27,413 39,069 20,208 9,615 96,305
USD per boe2 6.93 5.39 18.65 13.97 7.42
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 as a result of planned
infill well and well maintenance activity completed in Q3 2025 and wells A21 and A15 brought on production in late July 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 tangible fixed assets amounted to USD 1,419 thousand for Q3 2025 compared to USD 2,023
thousand for Q3 2024 and USD 4,797 thousand for the first nine months of 2025 compared to USD 6,503 thousand for the first
nine months of 2024. This relates to the depreciation of the FPSO Bertam, which has been 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 752 thousand for the first nine months of 2025
and USD 344 thousand for the first nine months of 2024.
Net financial items
Net financial items amounted to a charge of USD 21,030 thousand for Q3 2025 compared to a charge of USD 4,124 thousand for
Q3 2024 and a charge of USD 39,726 thousand for the first nine months of 2025 compared to a charge of USD 23,942 thousand
for the first nine months of 2024. Net financial items included a realized currency hedge loss of USD 8,039 thousand and a net
foreign exchange gain of USD 8,502 thousand for the first nine months of 2025 compared to no realized currency hedges and a
net foreign exchange gain of USD 1,743 thousand for the first nine 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 14,778 thousand for Q3 2025 compared to USD 9,484 thousand for Q3 2024 and a charge of USD 40,189 thousand for the
first nine months of 2025 compared to a charge of USD 25,685 thousand for the first nine months of 2024.
16
===== SIDA 38 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
The interest expense are stable and amounted to USD 10,082 thousand for Q3 2025 compared to USD 9,119 thousand for the
comparative period in 2024 and USD 27,823 thousand for the first nine months of 2025 compared to USD 26,865 thousand for the
first nine 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 501 thousand for Q3 2025 and USD 4,112 thousand for Q3 2024 and USD 2,829
thousand for the first nine months of 2025 compared to USD 14,646 thousand for the first nine months of 2024.
The unwinding of the asset retirement obligation discount rate amounted to USD 4,229 thousand for Q3 2025 compared to USD
3,680 thousand for Q3 2024 and USD 12,301 thousand for the first nine months of 2025 compared to USD 10,939 thousand for
the first nine months of 2024.
Income tax
The corporate income tax amounted to a charge of USD 3,030 thousand for Q3 2025 compared to a charge of USD 8,257
thousand for the comparative period in 2024 and a charge of USD 13,876 thousand for the first nine months of 2025 compared to
a charge of USD 29,473 thousand for the comparative period in 2024.
The current income tax amounted to a gain of USD 97 thousand for Q3 2025 and a charge of USD 754 thousand during the first
nine 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 nine months of 2025 was as follows:
USD Thousands
Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 223,043 6,424 39,161 4,782 273,410
Exploration and evaluation 3,529 – – – 3,529
226,572 6,424 39,161 4,782 276,939
Capital expenditures of USD 276,939 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 11,866 thousand as at September 30, 2025, which included USD 10,000 thousand in
respect of the FPSO Bertam. The FPSO Bertam has been depreciated to its residual value on a unit of production basis to August
2025.
Financial Position and Liquidity
Financing
As at September 30, 2025, IPC had MUSD 450 of senior secured unsecured 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 September 30, 2025, are classified as non-current as there are no mandatory repayments within the next twelve
months.
On September 25, 2025, IPC announced the placement of MUSD 450 of new senior unsecured bonds, maturing in October 2030
with a fixed coupon rate of 7.50% per annum, payable in semi-annual instalments in April and October, and with semi-annual
amortizations of MUSD 25 commencing in April 2028. The new bonds were issued in October 2025, with the proceeds being
used to fully redeem and cancel the previous bonds. IPC exercised its call option to redeem the previous bonds at a price equal
to 102.18% of the nominal amount, plus accrued and unpaid interest. The expected cash refinancing costs, which include the
call option costs of the senior unsecured bonds, and the related transaction costs, to be incurred in Q4 2025, are estimated at
approximately USD 18 million.
In addition, as at September 30, 2025, the Group had a senior secured revolving credit facility of MCAD 250 (the “Canadian RCF”)
in connection with its oil and gas assets in Canada, with a maturity date in May 2027. As at September 30, 2025 MCAD 37 (MUSD
27) was drawn under the Canadian RCF . As at September 30,2025, the Group also had a letter of credit facility in Canada (the “LC
Facility”) to cover operational letters of credit. As at September 30, 2025, operational letters of credit in an aggregate of MCAD
33.7 have been issued under the LC Facility, of which MCAD 24.5 relates to a third party pipeline construction agreement for the
Blackrod Phase 1 Development project which is expected to be released when the pipeline become operational.
As at September 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
September 30, 2025 was MUSD 2.9 which is classified as current representing the repayment planned within the next twelve
months.
17
===== SIDA 39 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
The Group is in compliance with the covenants of the bonds and its other credit facilities as at September 30, 2025.
Net debt as at September 30, 2025 amounted to MUSD 435. Cash and cash equivalents held amounted to MUSD 45 as at
September 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.
Working Capital
As at September 30, 2025, the Group had a working capital balance including cash of USD 512 thousand compared to USD
190,771 thousand as at December 31, 2024. The difference 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 and administrative expenses before depreciation and less cash financial items. Free cash flow is used to analyze
the amount of cash that is being generated by the business and that is available for such purposes as repaying debt, funding
acquisitions and returning capital to shareholders.
“EBITDA” is calculated as net result before financial items, taxes, depletion of oil and gas properties, exploration and business
development costs, impairment costs and depreciation and before for non-recurring profit/loss on sale of assets and other income.
“Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is
used to analyze the cash cost of producing the oil and gas volumes.
“Net debt” is calculated as bank loans and bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash
equivalents less bank loans and bonds.
Reconciliation of Non-IFRS Measures
Operating cash flow
The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended
September 30
Nine months ended
September 30
2025 2024 2025 2024
Revenue 172,297 173,200 509,681 598,659
Production costs and net sales of diluent to third party1 (106,292) (100,984) (313,162) (328,110)
Current tax 97 373 (754) (6,718)
Operating cash flow 66,102 72,589 195,765 263,831
1 Includes net sales of diluent to third party amounting to USD 91 thousand for the third quarter of 2025 and USD 510 thousand for the first nine
months of 2025.
18
===== SIDA 40 =====
Management’s Discussion and Analysis
For the three and nine months ended September 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
September 30
Nine months ended
September 30
2025 2024 2025 2024
Operating cash flow - see above 66,102 72,589 195,765 263,831
Capital expenditures (80,128) (99,100) (276,939) (308,457)
Abandonment and farm-in expenditures1 5,374 (2,575) 2,956 (4,938)
General and administrative expenses before depreciation2 (3,899) (3,903) (11,948) (11,245)
Cash financial items3 (10,532) (5,280) (34,341) (13,212)
Free cash flow (23,083) (38,269) (124,507) (74,021)
1 See notes 11 and 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
September 30
Nine months ended
September 30
2025 2024 2025 2024
Net result 3,802 22,875 33,883 101,804
Net financial items 21,030 4,124 39,726 23,942
Income tax 3,030 8,257 13,876 29,473
Depletion and decommissioning costs 32,245 30,491 90,582 96,305
Depreciation of other tangible fixed assets 1,419 2,023 4,797 6,503
Exploration and business development costs 184 197 752 344
Sale of assets1 – – (104) –
Depreciation included in general and administrative expenses2 396 346 1,059 933
EBITDA 62,106 68,313 184,571 259,304
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
September 30
Nine months ended
September 30
2025 2024 2025 2024
Production costs 106,383 100,984 313,672 328,110
Cost of blending (32,451) (29,818) (103,446) (116,699)
Change in inventory position (1,695) 2,755 5,076 3,160
Operating costs 75,627 73,921 215,302 214,571
19
===== SIDA 41 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
Net cash/(debt)
The following table sets out how net cash/(debt) is calculated:
USD Thousands September 30, 2025 December 31, 2024
Bank loans (29,483) (5,121)
Bonds1 (450,000) (450,000)
Cash and cash equivalents 44,661 246,593
Net cash/(debt) (434,822) (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 respect of the hedging of electricity prices; (e) MCAD 24.5 in respect of its obligations related to Blackrod
Phase 1 pipelines; and (f) MCAD 3.9 in respect of electricity distribution services.
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, with IPC being 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 September 30, 2025, IPC purchased 6,641,970 common shares under the NCIB and 261,818
common shares under certain other exemptions in Canada. During the first nine months of 2025, IPC cancelled 6,989,406 of these
purchased common shares, including the common shares held in treasury as at December 31, 2024. As at September 30, 2025,
IPC had a total of 112,180,065 common shares issued and outstanding, of which IPC held 24,538 common shares in treasury. In
October 2025, the shares held in treasury were cancelled and as at November 4, 2025, IPC had a total of 112,155,527 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 38.0% of the outstanding common shares as at September 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 November 4, 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 September 30, 2025:
MCAD 2025 2026 2027 2028 2029 Thereafter
Transportation service1 9.9 59.3 91.6 99.1 103.1 1,488.7
Power2 3.6 12.4 12.4 9.8 – –
Total commitments 13.5 71.7 104.0 108.9 103.1 1,488.7
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2047.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from October 1, 2025 to December
31, 2028, an additional 5MWh at a weighted average price of CAD 58.31/MWh from October 1, 2025 to December 31, 2027, and an additional
5MWh at a weighted average price of CAD 46.85/MWh from October 1, 2025 to December 31, 2025.
20
===== SIDA 42 =====
Management’s Discussion and Analysis
For the three and nine months ended September 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 nine 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 September 30, 2025, the Group 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 September 30, 2025, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
October 1, 2025 - December 31, 2025 11,700 WTI/WCS Differential USD -14.26/bbl
October 1, 2025 - December 31, 2025 10,000 WTI Sale Swap USD 71.30/bbl
October 1, 2025 - December 31, 2025 4,000 WTI Collar USD 65.00/bbl (Put)
USD 75.45/bbl (Call)
October 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 nine months ended September 30, 2025
The Group had gas price sale financial hedges outstanding as at September 30, 2025, which are summarized as follows:
Period Volume (Gigajoules (GJ) per
day)) Type Average Pricing
October 1, 2025 - October 31, 2025 20,000 AECO Swap CAD 2.25/GJ
October 1, 2025 - December 31, 2025 10,000 AECO Swap CAD 2.50/GJ
April 1, 2026 - October 31, 2026 10,000 AECO Swap CAD 2.65/GJ
The Group had electricity financial hedges outstanding as at September 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 11,101 thousand as at September 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 MCAD 97.5 for the period October 2025 to December 2025 at an average rate of CAD 1.36 (sell USD);
(ii) a total MEUR 6.75 for the period October 2025 to December 2025 at an average rate of EUR 1.08 (sell USD);
(iii) a total MMYR 30 for the period October 2025 to December 2025 at an average rate of MYR 4.38 (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 723 thousand as at September 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.
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.
22
===== SIDA 44 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
There have been no material changes to the Groups internal control over financial reporting during the three and nine months ended
September 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 September 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 ability of IPC to renew the NCIB and the number of common shares which may be purchased under a renewed NCIB;
• The intention and ability of IPC to acquire 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“.
23
===== SIDA 45 =====
Management’s Discussion and Analysis
For the three and nine months ended September 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 potential for further 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.
24
===== SIDA 46 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
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).
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.
25
===== SIDA 47 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a
classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity
that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best
estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered
will equal or exceed the best estimate.
Contingent resources are further classified based on project maturity. The project maturity subclasses include development
pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources
are classified as either development on hold or development unclarified. Development on hold is defined as a contingent
resource where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved
that are usually beyond the control of the operator. Development unclarified is defined as a contingent resource that requires
further appraisal to clarify the potential for development and has been assigned a lower chance of development until commercial
contingencies can be clearly defined. Chance of development is the probability of a project being commercially viable. Where
risked resources are presented, they have been adjusted based on the chance of development by multiplying the unrisked values
by the chance of development.
References to “unrisked“ contingent resources volumes means that the reported volumes of contingent resources have not
been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook for
contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies
required for the re-classification of the contingent resources as reserves being resolved. Therefore, unrisked reported volumes
of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such
resources.
The contingent resources reported in this MD&A are estimates only. The estimates are based upon a number of factors and
assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and
commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil
and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks
and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is
uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this MD&A.
2P reserves and contingent resources included in the reports prepared by Sproule and ERCE have been aggregated by IPC.
Estimates of reserves, resources and future net revenue for individual properties may not reflect the same level of confidence
as estimates of reserves, resources and future net revenue for all properties, due to aggregation. This MD&A contains estimates
of the net present value of the future net revenue from IPC’s reserves and contingent resources. The estimated values of future
net revenue disclosed in this MD&A do not represent fair market value. There is no assurance that the forecast prices and cost
assumptions used in the reserve and resources evaluations will be attained and variances could be material.
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.
Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel (bbl)
is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and
crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an
indication of value.
Supplemental Information regarding Product Types
The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily
production figures provided in this document:
Heavy Crude Oil
(Mbopd)
Light and Medium
Crude Oil (Mbopd)
Conventional Natural Gas
(per day)
Total
(Mboepd)
Three months ended
September 30, 2025 24.5 6.5 89.3 MMcf
(14.9 Mboe) 45.9
September 30, 2024 21.9 7.8 91.9 MMcf
(15.3 Mboe) 45.0
Nine months ended
September 30, 2025 23.5 6.3 89.1 MMcf
(14.8 Mboe) 44.6
September 30, 2024 23.7 7.9 94.8 MMcf
(15.8 Mboe) 47.4
Year ended
December 31, 2024 23.9 7.7 95.1 MMcf
(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 53% of that production will be comprised of heavy crude oil, approximately 14% will be comprised
of light and medium crude oil and approximately 33% will be comprised of conventional natural gas.
26
===== SIDA 48 =====
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025
OTHER SUPPLEMENTARY INFORMATION
Abbreviations
CAD Canadian dollar
MCAD Million Canadian dollar
EUR Euro
MEUR Million Euro
USD US dollar
MUSD Million US dollar
MYR Malaysian Ringgit
MMYR Million Malaysian Ringgit
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
27
===== SIDA 49 =====
Management’s Discussion and Analysis
For the three and nine months ended September 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
===== SIDA 50 =====
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□