Kvartalsrapport Q1 2026

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1
International Petroleum Corporation
Interim Condensed Consolidated 
Financial Statements
For the three months ended March 31, 2026

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2
Contents
Interim Condensed Consolidated Statement of Operations  3
Interim Condensed Consolidated Statement of Comprehensive Income/(Loss)  4
Interim Condensed Consolidated Balance Sheet  5
Interim Condensed Consolidated Statement of Cash Flow  6
Interim Condensed Consolidated Statement of Changes in Equity  7
Notes to the Interim Condensed Consolidated Financial Statements  8
Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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3
Interim Condensed Consolidated Statement of Operations
For the three months ended March 31, 2026 and 2025, UNAUDITED
Three months ended March 31
USD Thousands Note 2026 2025
Revenue 2 173,010 178,492
Cost of sales
Production costs 3 (105,001) (103,379)
Depletion and decommissioning costs 7 (29,931) (29,016)
Depreciation of other tangible fixed assets 7 – (1,917)
Exploration and business development costs (903) (31)
Gross profit 2 37,175 44,149
Other income/(expense) 3,975 285
General and administrative expenses (4,265) (4,669)
Profit before financial items 36,885 39,765
Net financial items 4 (20,737) (18,855)
Profit before tax 16,148 20,910
Income tax expense 5 (3,386) (4,679)
Net result 12,762 16,231
Net result attributable to:
Shareholders of the Parent Company 12,760 16,229
Non-controlling interest 2 2 
12,762 16,231
Earnings per share – USD
1 13 0.11 0.14
Earnings per share fully diluted – USD1 13 0.11 0.13
1  Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the interim condensed consolidated financial statements

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4
Interim Condensed Consolidated Statement of Comprehensive Income/(Loss)
For the three months ended March 31, 2026 and 2025, UNAUDITED
Three months ended March 31
USD Thousands Note 2026 2025
Net result 12,762 16,231
Other comprehensive income/(loss)
Items that may be reclassified to profit or loss:
Gain/(loss) on cash flow hedges (41,131) (5,137)
Reclassification of hedging (gains)/losses to profit or 
loss    2,422 10,290 8,074
Income tax relating to these items 7,262 (702)
Currency translation adjustments  (17,571) 3,946
Total comprehensive income/(loss)  (28,388) 22,412
Total comprehensive income attributable to:
Shareholders of the Parent Company  (28,388) 22,407
Non-controlling interest – 5
 (28,388) 22,412
See accompanying notes to the interim condensed consolidated financial statements

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5
Interim Condensed Consolidated Balance Sheet
As at March 31, 2026 and December 31 2025, UNAUDITED
USD Thousands Note March 31, 2026 December 31, 2025
ASSETS
Non-current assets
Exploration and evaluation assets 6 13,096 11,623
Property, Plant and Equipment 7 1,791,848 1,783,498
Right-of-use assets 3,220 3,070
Deferred tax assets 5 899 1,635
Derivative instruments 17 898 1,285
Other non-current assets 8 46,089 46,216
Total non-current assets 1,856,050 1,847,327
Current assets
Inventories
9 22,822 19,990
Trade and other receivables 10 124,604 97,220
Derivative instruments 17 – 1,644
Current tax receivables 4,959 4,411
Cash and cash equivalents 11 11,817 7,037
Total current assets 164,202 130,302
TOTAL ASSETS 2,020,252 1,977,629
LIABILITIES
Non-current liabilities
Financial liabilities
17 74,276 38,709
Bonds 17 442,728 442,324
Lease liabilities 3,146 2,956
Provisions 15 283,219 284,202
Deferred tax liabilities 5 116,043 122,013
Derivative instruments 17 912 –
Total non-current liabilities 920,324 890,204
Current liabilities
Trade and other payables
16 172,067 149,708
Financial liabilities 17 954 1,943
Derivative instruments 17 27,996 422
Current tax liabilities 55 216
Lease liabilities 933 930
Provisions 15 7,153 7,029
Total current liabilities 209,158 160,248
EQUITY
Shareholders’ equity 890,622 927,029
Non-controlling interest 148 148
Net shareholders’ equity 890,770 927,177
TOTAL EQUITY AND LIABILITIES 2,020,252 1,977,629
Approved by the Board of Directors
(Signed) C. Ashley Heppenstall    (Signed) William Lundin
Director       Director
See accompanying notes to the interim condensed consolidated financial statements

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6
Interim Condensed Consolidated Statement of Cash Flow
For the three months ended March 31, 2026 and 2025, UNAUDITED
Three months ended March 31
USD Thousands Note 2026 2025
Cash flow from operating activities
Net result 12,762 16,231
Depletion, depreciation and amortization 2,7  30,293 31,244
Gain on sale of asset  (3,793) –
Income tax 5  3,386 4,679
Amortization of capitalized financing fees 4  521 519
Foreign currency exchange loss/(gain) 4  6,268 (18)
Interest income 4  (125) (1,634)
Interest expense 4  9,560 8,761
Unwinding of asset retirement obligation discount  4,162 3,957
Share-based costs  2,700 2,261
Changes in working capital  (24,007) (2,289)
Decommissioning costs paid 15  (472) (321)
Other payments 15  (631) (703)
Net income taxes paid  (1,244) (2,134)
Interest received  135 2,142
Interest paid  (1,197) (16,351)
Other  206 245
Net cash flow from operating activities  38,524 46,589
Cash flow used in investing activities
Investment in oil and gas properties 7  (68,960) (98,886)
Investment in exploration and evaluation assets 6  (1,701) –
Disposal of assets  3,793 –
Investment in other tangible fixed assets 7  (101) (28)
Net cash (outflow) from investing activities  (66,969) (98,914)
Cash flow from financing activities
Proceeds from borrowings
14  159,581 –
Repayments of borrowings 14  (123,772) (672)
Repurchase of own shares (“NCIB”), including taxes 12  (1,956)  (53,187)
Lease payments  (330)  (218)
Net cash (outflow) from financing activities  33,523  (54,077)
Change in cash and cash equivalents 5,078 (106,402)
Cash and cash equivalents at the beginning of the period 7,037 246,593
Currency exchange difference in cash and cash 
equivalents (298) 3
Cash and cash equivalents at the end of the period 11,817 140,194
   
See accompanying notes to the interim condensed consolidated financial statements

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7
Interim Condensed Consolidated Statement of Changes in Equity
For the three months ended March 31, 2026 and 2025, UNAUDITED
USD Thousands
Share 
capital and 
premium
Retained 
earnings CTA IFRS 2 
reserve
MTM 
reserve
Pension 
reserve Total
Non-
controlling 
interest
Total
equity
Balance at January 1, 2026 40,909 896,692 (30,594) 19,515 1,913 (1,406) 927,029 148 927,177 
Net result – 12,760 – – – – 12,760 2 12,762
Cash flow hedges – – – – (23,579) – (23,579) – (23,579)
Currency translation difference – –  (17,720)  (173) 324 – (17,569) (2) (17,571)
Total comprehensive income – 12,760 (17,720) (173) (23,255) – (28,388) – (28,388)
Share based costs – – – 2,700 – – 2,700 – 2,700
Share based payments1 13,555 (13,538) – (10,736) – – (10,719) – (10,719)
Balance at March 31, 2026 54,464 895,914 (48,314) 11,306 (21,342) (1,406) 890,622 148 890,770 
1 The third instalment of IPC RSP 2023 awards, the second instalment of IPC RSP 2024 awards, the first instalment of IPC RSP 2025 awards and 
the IPC PSP 2023 awards vested on February 1, 2026, at a price of CAD 27.18 per award. The difference between the value at vesting date and 
at grant (respectively CAD 14.24 per award, CAD 14.82 per award, CAD 14.90 per award and CAD 11.51 per award) was offset against retained 
earnings. The impact from the issuance of common shares in settlement under IPC’s Share Unit Plan was recorded within share capital and share 
premium.
USD Thousands
Share 
capital and 
premium
Retained 
earnings CTA IFRS 2 
reserve
MTM 
reserve
Pension 
reserve Total
Non-
controlling 
interest
Total
equity
Balance at January 1, 2025 141,173 875,952 (81,192) 18,092 (13,138) (1,572) 939,315 155 939,470
Net result –  16,229     – – – –  16,229   2 16,231
Cash flow hedges – – – – 2,235 – 2,235 – 2,235
Currency translation difference – –  3,781     186    (24) –    3,943     3     3,946    
Total comprehensive income –     16,229     3,781     186     2,211    –      22,407     5     22,412    
Repurchase of own shares1 (53,187)    –   –    –    –   (53,187)   –     (53,187)    
Share based costs – – –   2,261    –     –      2,261    –    2,261    
Share based payments2 – (8,198)    –     (8,975)     –   –    (17,173)    –    (17,173)    
Balance at March 31, 2025  87,986     883,983    (77,411)     11,564    (10,927)   (1,572)     893,623     160     893,783    
1 See Note 12
2 The third instalment of IPC RSP 2022 awards, the second instalment of IPC RSP 2023 awards, the first instalment of IPC RSP 2024 awards and 
the IPC PSP 2022 awards vested on February 1, 2025, at a price of CAD 18.89 per award. The difference between the value at vesting date and 
at grant (respectively CAD 9.09 per award, CAD 14.24 per award, CAD 14.82 per award and CAD 8.40 per award) was offset against retained 
earnings. 
See accompanying notes to the interim condensed consolidated financial statements

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8
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED
1. CORPORATE INFORMATION AND MATERIAL ACCOUNTING POLICIES
A. The Group
International Petroleum Corporation (“IPC” or the “Corporation” and, together with its subsidiaries, the “Group”) is in the business 
of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development 
projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in 
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada under the Business Corporations Act. The 
address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is 
Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
B. Basis of preparation
The unaudited interim condensed consolidated financial statements have been prepared in accordance with IFRS Accounting
Standards applicable to the preparation of interim financial statements, under International Accounting Standard 34, Interim
Financial Reporting (together “IFRS Accounting Standards“). The unaudited interim condensed consolidated financial statements
should be read in conjunction with IPC’s annual audited consolidated financial statements for the year ended December 31, 2025,
which have been prepared in accordance with IFRS accounting standard 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 May 5, 2026.
The unaudited interim condensed consolidated financial statements have been prepared following the same accounting policies
and methods of application as those in the Group’s audited annual consolidated financial statements for the year ended December 
31, 2025.
C. Change in presentation
During the current period, IPC revised the presentation on the face of the Interim Condensed Consolidated Statement of 
Operations by presenting finance income and finance expenses on a consolidated basis within ‘Net financial items’. In addition, 
certain comparative figures have been reclassified to conform with the financial statements presentation in the current year.
D. Going concern
The Group’s unaudited interim condensed consolidated financial statements for the three months period ended March 31, 2026,
have been prepared on a going concern basis, which assumes that the Group will be able to realize its assets and discharge its
liabilities in the normal course of business as they become due in the foreseeable future.
E. Changes in accounting policies and disclosures
Recent amendments to IFRS 9 and related IFRS 7 disclosure requirements address the settlement of financial liabilities via 
electronic payment systems and refine the assessment of contractual cash flow characteristics for financial assets. The 
amendments are effective for annual reporting periods beginning on or after January 1, 2026. These changes have not a material 
impact on the financial statements.
IFRS 18 replaces IAS 1 and introduces expanded requirements for how financial information is presented and disclosed. The 
standard adds new subtotals, categories for income and expenses, and mandates disclosure of management performance 
measures. It also enhances rules around aggregation and disaggregation. Adoption is retrospective, and the Corporation is 
currently assessing system changes, preparing draft disclosures, and planning comparative restatements ahead of the 2027 
effective date.

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9
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED
2. SEGMENT INFORMATION
The Group operates within several geographical areas. Operating segments are reported at a country level which is consistent with 
the internal reporting provided to the CEO, who is the chief operating decision maker.
The following tables present segment information regarding: revenue, production costs, other operating costs and gross profit/
(loss). The Group derives its revenue from contracts with customers primarily through the transfer of oil and gas at a point in time. 
In addition, certain identifiable asset segment information is reported in Note 6 and 7.
Three months ended March 31, 2026
USD Thousands Canada Malaysia France Other Total
Crude oil 148,835 24,560 20,636 – 194,031
NGLs 143 – – – 143
Gas 12,342 – – – 12,342
Net sales of oil and gas 161,320 24,560 20,636 – 206,516
Change in under/over lift position – – (4,744) – (4,744)
Royalties (17,978) – (698) – (18,676)
Hedging settlement (10,290) – – – (10,290)
Other operating revenue – – 204 – 204
Revenue 133,052 24,560 15,398 – 173,010
Operating costs (49,220) (9,123) (9,896) – (68,239)
Cost of blending (38,891) – – – (38,891)
Change in inventory position 539 1,331 259 – 2,129
Depletion and decommissioning costs (20,593) (6,125) (3,213) – (29,931)
Exploration and business development costs – – – (903) (903)
Gross profit/(loss) 24,887 10,643 2,548 (903) 37,175
Three months ended March 31, 2025
USD Thousands Canada Malaysia France Other Total
Crude oil 162,022 15,376 12,814 – 190,212
NGLs 191 – – – 191
Gas 11,622 – – – 11,622
Net sales of oil and gas 173,835 15,376 12,814 – 202,025
Change in under/over lift position – – 1,141 – 1,141
Royalties (22,788) – (840) – (23,628)
Hedging settlement (1,216) – – – (1,216)
Other operating revenue – – 170 – 170
Revenue 149,831 15,376 13,285 – 178,492
Operating costs (52,505) (8,581) (8,067) – (69,153)
Cost of blending (37,726) – – – (37,726)
Change in inventory position 328 3,339 (167) – 3,500
Depletion and decommissioning costs (21,099) (5,751) (2,166) – (29,016)
Depreciation of other tangible fixed assets – (1,917) – – (1,917)
Exploration and business development costs – – – (31) (31)
Gross profit/(loss) 38,829 2,466 2,885 (31) 44,149

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Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED
3. PRODUCTION COSTS
Three months ended March 31
USD Thousands 2026 2025
Cost of operations 56,964 58,202 
Tariff and transportation expenses 10,118 9,944 
Direct production taxes 1,157 1,007 
Operating costs 68,239 69,153 
Cost of blending1 38,891 37,726 
Change in inventory position (2,129) (3,500)
Total production costs 105,001 103,379 
1  In Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. Cost of blending represents the contracted 
purchase of diluent used for blending.
4. NET FINANCIAL ITEMS
Three months ended March 31
USD Thousands 2026 2025
Interest income  125  1,634 
Interest expense  (9,560)  (8,761)
Unwinding of asset retirement obligation discount  (4,162)  (3,957)
Amortization of capitalized financing fees  (521)  (519)
Loan commitment fees  (167)  (230)
Foreign exchange gain/(loss), net  (6,268)  18 
Currency hedge gains/(loss), net –  (6,858)
Other financial costs  (184)  (182)
Total Net financial items  (20,737)  (18,855)

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11
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED
5. INCOME TAX
Three months ended March 31
USD Thousands 2026 2025
Current tax (456) (514)
Deferred tax (2,930) (4,165)
Total tax expense (3,386) (4,679)
Specification of deferred tax assets and tax liabilities1
USD Thousands March 31, 2026 December 31, 2025
Unused tax loss carry forward 67,477 65,825
Derivative hedges 6,667 –
Other 5,727 6,858
Deferred tax assets 79,871 72,683
Accelerated allowances 195,015 192,464
Derivative hedges – 597
Deferred tax liabilities 195,015 193,061
Deferred taxes, net (115,144) (120,378)
1  The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the 
balance sheet when they relate to the same jurisdiction.
The deferred tax liabilities consist of accelerated allowances, being the difference between the book and the tax value of oil and 
gas properties and site restoration provisions. The deferred tax liabilities will be released over the life of the oil and gas assets as 
the book value is depleted for accounting purposes. 
Deferred tax assets in relation to tax loss carried forwards are only recognized in so far that there is a reasonable certainty as to
the timing and the extent of their realization. The recognized unused tax loss carry forward mainly relates to Canada. The Group
has concluded that the deferred assets will be recoverable using the estimated future taxable income based on the approved
business plans and budgets.

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6. EXPLORATION AND EVALUATION ASSETS
USD Thousands Canada Malaysia France Total
Cost
January 1, 2026 11,623 – – 11,623
Additions 1,701 – – 1,701
Currency translation adjustments (228) – – (228)
Net book value March 31, 2026 13,096 – – 13,096
USD Thousands Canada Malaysia France Total
Cost
January 1, 2025 480 – – 480
Acquisitions 7,311 – – 7,311
Additions 5,036 – 15 5,051
Write-off – – (15) (15)
Reclassification (1,305) – – (1,305)
Currency translation adjustments 101 – – 101
Net book value December 31, 2025 11,623 – – 11,623
Impairment test
As of March 31, 2026, the Group determined that no internal or external indicators of impairment existed on its exploration and 
evaluation assets; therefore, the performance of an impairment test was determined not to be necessary (similar as of December 
31, 2025).
7. PROPERTY, PLANT AND EQUIPMENT
USD Thousands 2026 2025
Oil and gas properties                 1,780,662     1,772,278    
Other tangible fixed assets  11,186     11,220    
Property, Plant and Equipment  1,791,848  1,783,498
Oil and gas properties
USD Thousands Canada Malaysia France Total
Cost
January 1, 2026 2,141,610 640,581 465,622 3,247,813
Additions 67,728 561 671 68,960
Change in estimates (124) – – (124)
Currency translation adjustments (38,375) – (9,911) (48,286)
March 31, 2026 2,170,839 641,142 456,382 3,268,363
Accumulated depletion
January 1, 2026 (563,215) (554,509) (357,811) (1,475,535)
Depletion charge for the period (20,594) (6,125) (3,212) (29,931)
Currency translation adjustments 10,122 – 7,643 17,765
March 31, 2026 (573,687) (560,634) (353,380) (1,487,701)
Net book value March 31, 2026 1,597,152 80,508 103,002 1,780,662
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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USD Thousands Canada Malaysia France Total
Cost
January 1, 2025 1,767,580 599,734 405,129 2,772,443
Additions 286,570 40,877 5,759 333,206
Change in estimates (9,845) (30) 1,959 (7,916)
Reclassification 1,305 – – 1,305
Currency translation adjustments 96,000 – 52,775 148,775
December 31, 2025 2,141,610 640,581 465,622 3,247,813
Accumulated depletion
January 1, 2025 (451,017) (530,315) (306,624) (1,287,956)
Depletion charge for the year (87,449) (24,194) (11,106) (122,749)
Currency translation adjustments (24,749) – (40,081) (64,830)
December 31, 2025 (563,215) (554,509) (357,811) (1,475,535)
Net book value December 31, 2025 1,578,395 86,072 107,811 1,772,278
                 
Impairment test
As of March 31, 2026, the Group determined that no internal or external indicators of impairment existed on its oil and gas
properties; therefore, the performance of an impairment test was determined not to be necessary (similar as of December 31, 
2025).
     
Other tangible fixed assets
USD Thousands FPSO Other Total
Cost
January 1, 2026 204,853 11,247 216,100
Additions – 101 101
Currency translation adjustments – (191) (191)
March 31, 2026 204,853 11,157 216,010
Accumulated depreciation
January 1, 2026 (195,653) (9,227) (204,880)
Depreciation charge for the year – (99) (99)
Currency translation adjustments – 155 155
March 31, 2026 (195,653) (9,171) (204,824)
Net book value March 31, 2026 9,200 1,986 11,186
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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14
USD Thousands FPSO Other1 Total
Cost
January 1, 2025 204,853 9,824 214,677
Additions – 640 640
Disposals – (29) (29)
Currency translation adjustments – 812 812
December 31, 2025 204,853 11,247 216,100
Accumulated depreciation
January 1, 2025 (190,056) (8,196) (198,252)
Depreciation charge for the year (5,597) (397) (5,994)
Disposals – 29 29
Currency translation adjustments – (663) (663)
December 31, 2025 (195,653) (9,227) (204,880)
Net book value December 31, 2025 9,200 2,020 11,220
1  Depreciation of Other is included in General and administrative expenses in the statement of operations.
The Floating Production Storage and Offloading facility (“FPSO“) located on the Bertam field, Malaysia, has been depreciated to its 
residual value. 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.
8. OTHER NON-CURRENT ASSETS
USD Thousands March 31, 2026 December 31, 2025
Financial assets  34,622     34,545    
Intangible assets  11,467     11,671    
 46,089     46,216    
Financial assets mainly represent cash payments made in local currency to an asset retirement obligation fund for the Bertam 
field, Malaysia for an amount equivalent of USD 34.6 million (2025: USD 34.5 million), see note 15. 
Intangible assets mainly represent carbon offsets purchased in Canada. 
9. INVENTORIES
USD Thousands March 31, 2026 December 31, 2025
Hydrocarbon stocks 14,343 11,995 
Well supplies and operational spares 8,479 7,995 
22,822 19,990 
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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10. TRADE AND OTHER RECEIVABLES
USD Thousands March 31, 2026 December 31, 2025
Trade receivables  106,024     73,245    
Underlift  1,901     6,704    
Joint operations debtors  1,660     2,292    
Prepaid expenses and accrued income  9,120     8,437    
Other1  5,899     6,542    
124,604  97,220    
1  Other include a cash collateralized guarantee placed in respect of work commitments in Malaysia amounting to USD 4.0 million.
11. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include only cash at hand or held in bank accounts. 
12. SHARE CAPITAL
The Corporation’s issued common share capital is as follows:
Number of shares
Balance at January 1, 2025 119,169,471
Cancellation of repurchased common shares (7,013,944)
Balance at December 31, 2025 112,155,527
Issuance of common shares 671,225
Balance at March 31, 2026 112,826,752
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. The 
Corporation is authorized to issue an unlimited number of Common Shares without par value.
As at January 1, 2025, IPC had a total of 119,169,471 common shares issued and outstanding and held 110,156 common shares 
held in treasury.
Over the period of January 1, 2025 to December 4, 2025, IPC purchased and cancelled 6,641,970 common shares under the 
normal course issuer bid (NCIB) and 261,818 common shares under certain other exemptions in Canada. In the first quarter of 
2026, IPC paid USD 2 million of taxes in Canada in connection to the common shares repurchased in 2025 (or 2% of the total 
repurchase consideration).
As at December 31, 2025, IPC had a total of 112,155,527 common shares issued and outstanding, with no common shares held in 
treasury.
In February 2026, IPC issued 671,225 common shares in connection with the vesting of previously issued IPC Share Unit Plan 
awards. As at March 31, 2026, IPC had a total of 112,826,752 common shares issued and outstanding, with no common shares 
held in treasury.
                   
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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16
13. EARNINGS PER SHARE
Basic earnings per share are based on net result attributable to the common shareholders and is calculated based upon the 
weighted-average number of common shares outstanding during the years presented.
Three months ended March 31
2026 2025
Net result attributable to shareholders of the Parent Company, USD 12,760,212 16,228,987
Weighted average number of shares for the period  112,163,069 119,124,606
Earnings per share, USD  0.11 0.14
Weighted average diluted number of shares for the period  113,260,665  120,309,604 
Earnings per share fully diluted, USD  0.11 0.13
14. FINANCIAL LIABILITIES
USD Thousands March 31, 2026 December 31, 2025
Current bank loans 954 1,943
Non current bank loans 74,276 38,709
Bonds 450,000 450,000
Capitalized financing fees (7,272) (7,676)
517,958 482,976
As at January 1, 2025, IPC had USD 450 million of senior unsecured bonds outstanding, maturing in February 2027 with a fixed 
coupon rate of 7.25% per annum. In October 2025, IPC completed the issuance of USD 450 million of new senior unsecured 
bonds, maturing in October 2030 with a fixed coupon rate of 7.50% per annum, payable in semi-annual instalments in April and 
October, and with semi-annual amortizations of USD 25 million commencing in April 2028. The proceeds of the new bonds were 
used to fully redeem and cancel the previous bonds.
The bond repayment obligations as at March 31, 2026, are classified as non-current as there are no mandatory repayments within 
the next twelve months.
In addition, as at March 31, 2026, 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 March 31, 2026, CAD 104 million 
(approximately USD 74 million) was drawn under the Canadian RCF . In April 2026, the Group amended and extended the Canadian 
RCF , increasing the committed facility size to CAD 348.5 million and extending the maturity to May 2028. As at March 31, 2026, 
the Group also had a letter of credit facility in Canada (the “LC Facility”). As at March 31, 2026, operational letters of credit in an 
aggregate of CAD 11.9 million have been issued under the LC Facility.
As at March 31, 2026, IPC had an unsecured Euro credit facility in France (the “France Facility“) which will be fully repaid in May
2026. The  outstanding under the France Facility as at March 31, 2026 was USD 1 million (EUR 0.8 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 March 31, 2026.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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

17
15. PROVISIONS
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2026  284,532     1,230     3,372     2,097     291,231    
Additions  –      – –  141     141    
Unwinding of asset retirement obligation discount  4,162    – – –  4,162    
Payments (472)    – – (631)    (1,103)    
Change in estimates (124)    – – – (124)    
Currency translation adjustments (3,916)     4    – (23)    (3,935)    
March 31, 2026  284,182     1,234     3,372     1,584     290,372    
Non-current  278,263    –  3,372     1,584     283,219    
Current  5,919     1,234    – –  7,153    
Total  284,182     1,234     3,372     1,584     290,372    
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2025 267,790 1,679 3,685 2,072 275,226
Additions – – 816 815 1,631
Unwinding of asset retirement obligation discount 16,498 – – – 16,498
Payments (5,967) (587) (963) (897) (8,414)
Change in estimates (7,916) – (654) – (8,570)
Reclassification1 725 – – – 725
Currency translation adjustments 13,402 138 488 107 14,135
December 31, 2025 284,532 1,230 3,372 2,097 291,231
Non-current 278,733 – 3,372 2,097 284,202
Current 5,799 1,230 – – 7,029
Total 284,532 1,230 3,372 2,097 291,231
1 The reclassification of the asset retirement obligation related to the 2025 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 8). 
The farm-in obligation relates to future payments for historic costs on the Bertam field in Malaysia payable for every 1 MMb oe 
gross that the field produces above 10 MMboe gross and is capped at cumulative production of 27.5 MMboe gross. 
In calculating the present value of the asset retirement obligation provision, a blended discount rate of 6% (2025: 6%) per annum 
was used, based on a credit risk adjusted rate. The calculation also assumes that the costs are inflated by 2% a year (2025: 2%) 
The payment of these obligations is spread over a period of 60 years.
16. TRADE AND OTHER PAYABLES
USD Thousands March 31, 2026 December 31, 2025
Trade payables  48,855     39,377    
Joint operations creditors  2,366     2,198    
Accrued expenses  115,003     101,353    
Other  5,843     6,780    
 172,067     149,708    
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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

18
17. FINANCIAL ASSETS AND LIABILITIES
Financial assets and liabilities by category
The accounting policies for financial instruments have been applied to the line items below:
March 31, 2026
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1  34,622  34,622 – –
Derivative instruments  898  – – 898
Joint operation debtors  1,660  1,660 – –
Other current receivables2  118,783  116,882  1,901 –
Cash and cash equivalents  11,817  11,817 – –
Financial assets  167,780  164,981  1,901 898
1 See Note 8
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
March 31, 2026
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities  517,004  517,004 – –
Current financial liabilities  954  954 – –
Derivative instruments  28,908 – –  28,908 
Joint operation creditors  2,366  2,366 – –
Other current liabilities  169,756  169,756 – –
Financial liabilities  718,988  690,080 –  28,908 
December 31, 2025
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 34,545 34,545 – –
Derivative instruments 2,929 – – 2,929
Joint operation debtors 2,292 2,292 – –
Other current receivables2 86,745 84,198 6,704 –
Cash and cash equivalents 7,037 7,037 – –
Financial assets 137,705 128,072 6,704 2,929
1 See Note 8
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
December 31, 2025
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 481,033 481,033 – –
Current financial liabilities 1,943 1,943 – –
Derivative instruments 422 – – 422
Joint operation creditors 2,198 2,198 – –
Other current liabilities 147,726 147,726 – –
Financial liabilities 633,322 632,900 – 422
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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

19
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:
March 31, 2026
USD Thousands Level 1 Level 2 Level 3
Other current receivables 1,901 – –
Derivative instruments – current – – –
Derivative instruments – non-current – 898 –
Financial assets 1,901 898 –
Derivative instruments – current – 27,480 516
Derivative instruments – non-current – – 912
Financial liabilities – 27,480 1,428
December 31, 2025
USD Thousands Level 1 Level 2 Level 3
Other current receivables 6,704 – –
Derivative instruments – current – 1,644 –
Derivative instruments – non-current – – 1,285
Financial assets 6,704 1,644 1,285
Derivative instruments – current – – –
Derivative instruments – non-current – – 422
Financial liabilities – – 422
The Group had oil price sale financial hedges outstanding as at March 31, 2026 which are summarized as follows:
Period Volume (barrels 
per day) Type Average Pricing 
April 1, 2026 - June 30, 2026 9,000 WTI Sale Swap USD 62.36/bbl
April 1, 2026 - December 31, 2026 5,000 WTI/WCS Differential USD -12.50/bbl
July 1, 2026 - December 31, 2027 5,000 WCS (Hardisty vs Houston)1 USD -7.55/bbl
July 1, 2026 - December 31, 2026 2,000 ARV2 USD -3.65/bbl
April 1, 2026 - June 30, 2026 2,000 Brent Sale Swap USD 68.06/bbl
1 Represents the cost of transporting a barrel of WCS quality from Hardisty to Houston.
2 Represents the difference in USD of a barrel of WCS in Houston against a barrel of WTI quality.
The Group had gas price sale financial hedges outstanding as at March 31, 2026 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
April 1, 2026 - October 31, 2026 15,000 AECO Gas Swap CAD 2.73/GJ
The Group had electricity financial hedges outstanding as at March 31, 2026 which are summarized as follows:
Period Volume (MW) Type Average Pricing 
April 1, 2026 - September 30, 2040 3 AESO CAD 75.00/MWh
All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, UNAUDITED

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

20
18. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In the normal course of business, the Group has committed to certain payments which are not recognized as liabilities. The 
following table summarizes the Group’s commitments in Canada as at March 31, 2026:
CAD Millions 2026 2027 2028 2029 2030 Thereafter
Transportation service1 45.8 83.8 99.5 100.8 101.7 1,355.0
Power2 9.3 12.4 9.8 – – –
Total commitments 55.1 96.2 109.3 100.8 101.7 1,355.0
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2046.
2  IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from April 1, 2026 to December
31, 2028, and an additional 5MWh at a weighted average price of CAD 58.31/MWh from April 1, 2026 to December 31, 2027.
19. RELATED PARTIES
The Group recognizes the following related parties: associated companies, jointly controlled entities, key management personnel 
and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or 
of its family or of any individual that controls, or has joint control or significant influence over the entity.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with 
parties at arm’s length.
During the first quarter of 2026, the Group has not entered into material transactions with related parties.
20. SUBSEQUENT EVENTS
In April 2026, the Group amended and extended the Canadian RCF , increasing the committed facility size to CAD 348.5 million and 
extending the maturity to May 2028.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2026 and 2025, 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 =====

International Petroleum Corporation
Management’s Discussion
and Analysis
For the three months ended March 31, 2026
1

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Contents
Non-IFRS Measures
References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization”  
(EBITDA), “operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under IFRS Accounting Standards (“IFRS”) and do 
not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF, FCF, EBITDA, operating costs and net debt/
net cash that may be used by other public companies. Management believes that OCF, FCF, EBITDA, operating costs and net debt/net cash are useful supplemental 
measures that may assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Non-IFRS 
measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS 
measure is presented in this MD&A. See “Non-IFRS Measures” on page 15.
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 20.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada and France/Malaysia are 
effective as of December 31, 2025, and are included in the reports prepared by Sproule International Limited and ERC Equipoise Ltd., respectively (collectively, 
Sproule ERCE), an independent qualified reserves evaluator and auditor, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas 
Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule ERCE’s December 31, 2025, price forecasts.
Certain abbreviations and technical terms used in this MD&A are defined or described under the heading “Other Supplementary Information”.
INTRODUCTION  3
HIGHLIGHTS  4
OPERATIONS REVIEW  5
• Business Overview 5
• Operations Overview  7
FINANCIAL REVIEW  9
• Financial Results 9
• Capital Expenditure 14
• Financial Position and Liquidity  14
• Non-IFRS Measures  15
• Off-Balance Sheet Arrangements  17
• Outstanding Share Data  17
• Contractual Obligations and Commitments  17
• Material Accounting Policies and Estimates 18
• Transactions with Related Parties  18
• Financial Risk Management  18
RISK FACTORS 20
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING  20
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION  20
RESERVES AND RESOURCES ADVISORY  23
OTHER SUPPLEMENTARY INFORMATION  25
2

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
INTRODUCTION
This management’s discussion and analysis (“MD&A”) for International Petroleum Corporation (“IPC” or the “Corporation” and, 
together with its subsidiaries, the “Group”) is dated May 5, 2026 and is intended to provide an overview of the Group’s operations, 
financial performance and current and future business opportunities. This MD&A should be read in conjunction with IPC’s 
unaudited interim condensed consolidated financial statement for the period ended March 31, 2026 as well as the audited
consolidated financial statements and accompanying notes for the year ended December 31, 2025 (“Financial Statements”).
Group Overview
The Group is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production 
assets and development projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in 
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada, under the Business Corporations Act. The 
address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is 
Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
Basis of Preparation
The MD&A and the Financial Statements have been prepared in accordance with IFRS Accounting Standards (“IFRS”) as issued by 
the International Accounting Standards Board (“IASB”). 
Financial information is presented in United States Dollars (“USD”). However, as the Group operates in Europe and in Canada, 
certain financial information prepared by subsidiaries has been reported in Euros (“EUR”) and in Canadian Dollars (“CAD”). In 
addition, certain costs relating to the operations in Malaysia, which are reported in USD, are incurred in Malaysian Ringgit (“MYR”). 
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
March 31, 2026 March 31, 2025 December 31, 2025
Average Period end Average Period end Average Year end
1 EUR equals USD 1.1707 1.1498 1.0807 1.0815 1.1293 1.1750
1 USD equals CAD 1.3724 1.3935 1.4352 1.4362 1.3975 1.3692
1 USD equals MYR 3.9638 4.0490 4.4475 4.4375 4.2791 4.0580
              
3

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
HIGHLIGHTS
Q1 2026 Business Highlights
• Average net production of approximately 43,000 boepd for the first quarter of 2026, at the high end of the guidance range for 
the period (52% heavy crude oil, 15% light and medium crude oil and 33% natural gas).(1)
• Blackrod Phase 1 development activity nears completion as final construction activities and commissioning of the Central 
Processing Facility (CPF) advance, with first oil forecast for Q3 2026.
• Following the increase in commodity prices in Q1 2026, decision taken to increase 2026 planned capital activities, with an 
additional MUSD 41 of forecast capital expenditures over the remainder of 2026.
Q1 2026 Financial Highlights
• Operating costs per boe of USD 17.6 for Q1 2026, ahead of guidance.(3)
• Operating cash flow (OCF) generation of MUSD 68 for Q1 2026, ahead of guidance. (3)
• Capital and decommissioning expenditures of MUSD 71 for Q1 2026, in line with guidance.
• Free cash flow (FCF) generation for Q1 2026 amounted to MUSD -17.(3)
• Net result of MUSD 13 for Q1 2026.
• Amended and extended the credit facility in Canada in Q2 2026 to increase the committed facility size to CAD 348.5 million 
(approximately USD 250 million), with maturity extended to May 2028.
Reserves and Resources
• Total 2P reserves as at December 31, 2025 of 521 MMboe, with a reserve life index (RLI) of 31 years.(1)(2)
• Contingent resources (best estimate, unrisked) as at December 31, 2025 of 1,224 MMboe. (1)(2)
2026 Annual Guidance
• Full year 2026 average net production guidance range maintained at 44,000 to 47,000 boepd. (1)
• Full year 2026 operating costs guidance range maintained at USD 18 to 20 per boe. (3)
• Full year 2026 OCF revised guidance estimated at between MUSD 220 and 340 (assuming Brent USD 70 to 90 per barrel for 
the remainder of 2026) from previous guidance of between MUSD 100 and 250 (assuming Brent USD 55 to 75 per barrel).
(3)(4)
• Full year 2026 capital and decommissioning expenditures guidance forecast increased to MUSD 163, as a result of additional 
planned capital activities.
• Full year 2026 FCF revised guidance estimated at between MUSD 0 and 120 (assuming Brent USD 70 to 90 per barrel for the 
remainder of 2026) from previous guidance of between negative MUSD 70 and positive MUSD 85 (assuming Brent USD 55 
to 75 per barrel).
(3)(4)
Three months ended March 31
USD Thousands 2026 2025
Revenue  173,010 178,492
Gross profit  37,175 44,149
Net result  12,762 16,231
Operating cash flow(3)  67,735 74,790
Free cash flow(3)  (17,086) (43,172)
EBITDA(3)  64,289 70,946 
Net cash/(debt)(3)  (513,413) (314,255)
4

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
OPERATIONS REVIEW 
Business Overview
During the first quarter of 2026, commodity prices increased materially compared to the prior quarter, with Brent oil prices 
averaging over USD 80 per barrel. During the quarter and into the second quarter, commodity prices continued to be high and 
volatile mainly in response to uncertainties with respect to the conflict in the Middle East and the corresponding effects on supply 
of oil and gas from the region. As a result of the constrained flows through the Strait of Hormuz from the end of February, one
of the largest supply disruptions on record has taken place with an estimated net 10 million barrels per day shortfall. This has 
prompted coordinated Strategic Petroleum Reserves releases, increased OPEC spare capacity unwinds, and relief on previously 
sanctioned Russian and Iranian barrels to combat high crude and crude product prices. Prompt spreads between physical spot and 
Brent futures month contracts have seen all time high price separation signalling extreme physical market tightness due to the 
supply disruption. The profound effect of this crisis is likely to be much longer lasting as consumers and producers alike reshape 
their thinking around access to resources and security of supply. Prior to the commencement of hostilities in Iran, IPC hedged 
2,000 barrels per day of Dated Brent from April to June 2026 at around USD 68 per barrel and 9,000 barrels per day of West Texas 
Intermediate (WTI) from April to June 2026 at around USD 62 per barrel. IPC remains fully exposed to benchmark oil prices from 
the beginning of July 2026 onwards.
The first quarter 2026 WTI to Western Canadian Select (WCS) price differential averaged USD 14 per barrel, in line with the 2026 
forecast. 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 outlook of the WTI to WCS differential remains tight with excess egress capacity 
relative to the supply in the Western Canadian Sedimentary Basin (WCSB), balanced against the potential of Venezuelan heavy oil 
barrels to the US Gulf Coast PADD III refineries. There are currently no tariffs on Canadian crude oil exports to the United States, 
which remain covered by the US Mexico Canada trade agreement. For 2026, IPC has implemented WTI to WCS differential 
hedges for 5,000 barrels per day at USD -12.50 per barrel. In addition, IPC has hedged from July to year end 2027, 5,000 barrels 
per day of the differential between the WCS price in Hardisty, Canada and the WCS price in Houston, USA, effectively hedging the 
transportation cost between the locations, at USD -7.55 per barrel. In addition, 2,000 barrels per day of quality differential between 
the WCS in Houston and the WTI were hedged from July to December 2026 at USD -3.65 per barrel.
The average Canadian gas benchmark price, AECO, was CAD 1.98 per Mcf for the first quarter of 2026, with WCSB gas inventory 
levels remaining elevated above the historical average. There is an expectation that the ramp up of the LNG Canada project in 2026 
should drive higher natural gas prices in Canada. IPC has implemented hedges for 15,000 GJ (approximately 14,500 Mcf) per day 
at CAD 2.73 per GJ (approximately CAD 2.84 per Mcf) for 2026 from April to October 2026.
First Quarter 2026 Highlights and Full Year 2026 Guidance
During the first quarter of 2026, our portfolio delivered average net production of 43,000 boepd, at the high end of the guidance 
range for the quarter. Operational performance from our producing assets was strong to start the year as high facility and well 
uptimes were achieved. We maintain the full year 2026 average net production guidance range of 44,000 to 47,000 boepd.
(1)
Our operating costs per boe for the first quarter of 2026 was USD 17.6, ahead of guidance. Full year 2026 operating expenditure 
guidance of USD 18.0 to 20.0 per boe remains unchanged.
(3)
Operating cash flow (OCF) generation for the first quarter of 2026 was USD 68 million. Full year 2026 OCF guidance is increased 
to USD 220 to 340 million (assuming Brent USD 70 to 90 per barrel for the remainder of 2026).
(3)(4)
Capital and decommissioning expenditure for the first quarter of 2026 was USD 71 million in line with guidance. Full year 2026 
capital and decommissioning expenditure is increased to USD 163 million following the decision to accelerate capital activities 
following the 2026 commodity price increases.
Free cash flow (FCF) generation was USD –17 million during the first quarter of 2026, ahead of guidance. Full year 2026 FCF 
guidance is increased to USD 0 to 120 million (assuming Brent USD 70 to 90 per barrel for the remainder of 2026).
(3)(4)
As at March 31, 2026, IPC’s net debt position was USD 513 million, from a net debt position of USD 484 million as at December 
31, 2025, mainly driven by the funding of Blackrod project capital expenditures.
In April 2026, IPC increased the facility size of its Canadian credit facility to CAD 348.5 million (approximately USD 250 million) 
and extended the maturity of the facility to May 2028. IPC previously announced the 2025 refinancing of its USD 450 million of 
unsecured bonds, with maturity in October 2030. This enhanced liquidity position for the company, combined with the better than 
forecast cash flow generation to date and forecast for 2026, supports IPC in following through on its key strategic objectives to 
maximize stakeholder value.
 
IPC maintains the ability to repurchase up to approximately 6.5 million common shares up to early December 2026 under the 
renewed normal course issuer bid (NCIB) announced in Q4 2025. IPC has not purchased any common shares under the 2025/2026 
NCIB to date. As at March 31, 2026 and May 5, 2026, IPC had a total of 112,826,752 common shares issued and outstanding and 
IPC held no common shares in treasury.
5

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Blackrod
The Blackrod asset is 100% owned by IPC and hosts the largest booked reserves and contingent resources within the IPC 
portfolio. After more than a decade of pilot operations, subsurface delineation and commercial engineering studies, IPC sanctioned 
the Phase 1 SAGD development in the first quarter of 2023. The Phase 1 development targets 311 MMboe of 2P reserves, with  
first oil planned in Q3 2026 and a plateau production of 30,000 bopd by the end of 2027.
(1)(2)
As previously announced, IPC achieved first steam at the Blackrod Phase 1 project in December 2025, a quarter earlier than 
originally guided at the time of project sanction. By the end of the first quarter of 2026, approximately USD 842 million of 
cumulative growth capital has been spent on the Blackrod Phase 1 development since sanction. Construction is nearing 
completion at the Central Processing Facility (CPF) and well pad facilities, commissioning activities are progressing in line with 
schedule, and drilling plus completions have been completed in line with plan. Site health and safety control has been excellent 
with no lost time incidents since commercial development activities commenced.
IPC remains well-positioned to responsibly deliver the Phase 1 project in line with the multi-year budget of USD 850 million to first 
oil. The total growth capital expenditure comprises the total installed costs for the facilities and associated 40 well pairs needed to 
fill the plant capacity of 30,000 bopd and has remained unchanged since the time of sanction in 2023.
(1)
Blackrod is a multi-generational asset that is being unlocked through the first phase of commercial development. More than 1.45 
billion barrels of recoverable resource lies within the contiguous reservoir wholly owned by IPC. The company remains laser 
focused on achieving the production start and ramp up targets as previously disclosed on the Phase 1 project and in parallel is 
maturing future phase expansion concepts. Blackrod has regulatory approval for up to 80,000 bopd.
(1)(2)
Environmental, Social and Governance (ESG) Performance
As part of IPC’s commitment to operational excellence and responsible development, IPC’s objective is to reduce risk and 
eliminate hazards to prevent occurrence of accidents, ill health, and environmental damage, as these are essential to the success 
of our business operations. During the first quarter of 2026, IPC recorded no material safety or environmental incidents.
Notes:
(1) See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory” below. See also the 
annual information form for the year ended December 31, 2025 (AIF) available on IPC’s website at www.international-
petroleum.com and under IPC’s profile on SEDAR+ at www.sedarplus.ca.
(2) See “Reserves and Resources Advisory“ below. Further information with respect to IPC’s reserves, contingent resources 
and estimates of future net revenue, including assumptions relating to the calculation of net present value (NPV), are 
described in the AIF . 
(3) Non-IFRS measures, see “Non-IFRS Measures” below and in the MD&A. 
(4) OCF and FCF forecasts at Brent USD 70 to 90 per barrel assume Brent to WTI differential of USD 5 per barrel and WTI to 
WCS differential of USD 14 per barrel for the remainder of 2026. OCF and FCF forecasts assume gas price on average of 
approximately CAD 2.17 per Mcf for the remainder of 2026. 
6

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Operations Overview 
Q1 2026 Overview
In Q1 2026, IPC continued to successfully demonstrate its commitment to operational excellence, delivering high end production 
performance with strong cost discipline resulting in operating expenditure at the low end of our Capital Markets Day (CMD) 
guidance. No material safety or environmental incidents were recorded in the quarter. 
At the end of Q1 2026, on the back of the strong pricing environment and the strong operational performance year to date, IPC 
has increased the 2026 capital expenditure budget by MUSD 41 to allow additional production well drilling activities in France and 
Canada. In France, three sidetrack wells are planned to be drilled as part of the first phase of development of the Fontaine-au-Bron 
field, in addition to one sidetrack well planned at the Villeperdue field. In Canada, oil production well drilling in the Suffield Basal 
Quartz formation is expected to recommence with the sanction of four additional production wells planned to be executed in 2026. 
The incremental activity is forecast to raise 2026 exit rates and support higher production levels into 2027. The planned 4D seismic 
activity has been acquired at Onion Lake Thermal with reprocessing ongoing in preparation for the potential next phase of infill 
production well drilling.
At the Blackrod Phase 1 development, the remaining project scope and overall project budget continued to progress in line with 
guidance. By the end of Q1 2026, project construction activities are near completion, while commissioning has entered its final 
stages, with activities expected to ramp down towards the summer. The production and injection well pair warm-up process, 
through steam circulation, is ongoing, with a total of 30 well pairs brought onto steam circulation by the end of Q1 2026. To take 
advantage of economies of scale and provide additional well capacity, IPC accelerated the drilling of sixteen well pairs on the final 
pad starting in Q4 2025, delivering six additional sustaining well pairs beyond the original Phase 1 development budget. Drilling 
operations were completed ahead of schedule in Q1 2026, and commissioning of the final well pad facilities is currently ongoing, 
with completion expected in Q3 2026. Final third-party export pipeline commissioning was completed as planned in Q1 2026 and, 
at quarter-end, all three third party utility and export lines were operational.
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 521 MMboe as at December 31, 2025, as certified by IPC’s 
independent third-party reserve auditor and evaluator. The 2P reserve life index (RLI) as at December 31, 2025, is approximately 31 
years. Best estimate contingent resources as at December 31, 2025, are 1,224 MMboe (unrisked). See “Reserves and Resources 
Advisory” below.
Production
Average daily net production for Q1 2026 was in line with IPC’s CMD guidance at 43,000 boepd with strong operational 
performance in all regions.
With the first quarter 2026 operational delivery, and a robust production outlook for the remainder of the year, IPC remains well 
positioned to deliver an annual net average daily production within the guidance range of 44,000 to 47,000 boepd.
The production during Q1 2026 with comparatives is summarized below:
Production
in Mboepd
Three months ended
March 31
Year ended
December 31
2026 2025 2025
Crude oil
Canada – Northern Assets 14.2 13.9 14.7
Canada – Southern Assets 9.2 10.8 10.2
Malaysia 3.3 2.9 3.0
France 2.0 2.1 2.1
Total crude oil production 28.7 29.7 30.0
Gas
Canada – Northern Assets 0.5 0.5 0.4
Canada – Southern Assets 13.8 14.2 14.5
Total gas production 14.3 14.7 14.9
Total production 43.0 44.4 44.9
Quantity in MMboe 3.87 4.00 16.38
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
7

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
CANADA
Production
in Mboepd
Working Interest
(WI)
Three months ended
March 31
Year ended
December 31
2026 2025 2025
- Oil Onion Lake Thermal 100% 11.8 11.5 12.2
- Oil Suffield Area 100% 8.2 9.3 8.9
- Oil Other 50-100% 3.4 3.9 3.8
- Gas ~100% 14.3 14.7 14.9
Canada 37.7 39.4 39.8
Production
Net production from IPC’s assets in Canada during Q1 2026 was in line with guidance at 37.7 Mboepd with continued strong 
operational performance at the major oil and gas producing assets.
Organic Growth and Capital Projects
In Canada, with the forecast final development spend year at the Blackrod Phase 1 project, IPC announced a balanced non- 
Blackrod capital expenditure budget for 2026. In response to the improved commodities pricing environment, IPC intends to take 
advantage of operatorship across its assets by increasing short cycle production activities.
At Suffield, drilling of the Basal Quartz formation is planned to recommence with an additional four production wells scheduled to 
commence drilling in Q3 2026. 
At Onion Lake Thermal, the 4D seismic data is being reprocessed as IPC looks to mature the potential next phase of infill well 
targets and to optimize future sustaining pad well locations.
At Blackrod Phase 1, remaining scope and total project budget continued to progress in line with guidance. By the end of Q1 2026, 
construction activities were nearing completion, and commissioning was in the final stages, with activity levels expected to reduce 
toward the summer. Steam circulation warm-up of the production and injection well pairs were ongoing, with 30 well pairs on 
steam circulation at quarter end. Drilling of the final well pad was completed ahead of schedule in Q1 2026, with commissioning 
ongoing and expected to be completed in Q3 2026. Commissioning of the third party export pipeline was completed as planned in 
Q1 2026, and all utility and export lines were operational at quarter end.
MALAYSIA
Production
in Mboepd WI
Three months ended
March 31
Year ended
December 31
2026 2025 2025
Bertam 100% 3.3 2.9 3.0
Production
Net production in Malaysia during Q1 2026 was in line with guidance at 3.3 Mboepd.
Organic Growth and Capital Projects
Limited planned well maintenance at the Bertam field is scheduled for execution early in Q3 2026. 
FRANCE
Production
in Mboepd WI
Three months ended
March 31
Year ended
December 31
2026 2025 2025
France
- Paris Basin 100% 1.7 1.9 1.8
- Aquitaine 50% 0.3 0.2 0.3
2.0 2.1 2.1 
8

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Production
Net production in France during Q1 2026 was in line with guidance at 2.0 Mboepd with stable performance across all the major 
producing fields.
Organic Growth
In France, three sidetrack wells are planned to be drilled as part of the first phase of development of the Fontaine-au-Bron field, in 
addition to one sidetrack well planned at the Villeperdue field. Drilling operations are on track to commence in Q2.
  
FINANCIAL REVIEW 
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q1-26 Q4-25 Q3-25 Q2-25 Q1-25 Q4-24 Q3-24 Q2-24
Revenue  173,010 176,207 172,297 158,892 178,492 199,124 173,200 219,040
Gross profit  37,175 28,242 32,066 23,663 44,149 42,774 39,505 72,708
Net result  12,762 (4,942) 3,802 13,850 16,231 415 22,875 45,210
Earnings per share – USD 0.11 (0.04) 0.03 0.12 0.14 0.00 0.19 0.36
Earnings per share fully
diluted – USD 0.11 (0.04) 0.03 0.12 0.13 0.00 0.18 0.36
Operating cash flow1  67,735 63,138 66,102 54,873 74,790 78,158 72,589 101,941
Free cash flow1  (17,086) (28,627) (23,083) (58,252) (43,172) (61,476) (38,269) 7,559
EBITDA1  64,289 58,966 62,106 51,519 70,946 76,184 68,313 103,971
Net cash/(debt) at period end1  (513,413) (483,615) (434,822) (374,977) (314,255) (208,528) (157,228) (88,220)
1 See definition on page 15 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands March 31, 2026 December 31, 2025
Non-current assets  1,856,050 1,847,327
Current assets  164,202 130,302
Total assets  2,020,252 1,977,629
Total non-current liabilities  920,324 890,204
Current liabilities  209,158 160,248
Total liabilities  1,129,482 1,050,452
Net assets  890,770 927,177
Working capital (including cash)  (44,956) (29,946)
9

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Selected Interim Financial Information
The Group operates within several geographical areas. Operating segments are reported at a country level, with Canada being 
further analyzed by main areas: (i) Canada – Northern Assets (comprising mainly of the Onion Lake Thermal asset) and (ii) Canada – 
Southern Assets (comprised mainly of the Suffield area assets). This is consistent with the internal reporting provided to the CEO, 
who is the chief operating decision maker. The following tables present certain segment information.
Three months ended – March 31, 2026
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 97,751 51,084 24,560 20,636 – 194,031
NGLs – 143 – – – 143
Gas 94 12,248 – – – 12,342
Net sales of oil and gas 97,845 63,475 24,560 20,636 – 206,516
Change in under/over lift position – – – (4,744) – (4,744)
Royalties (12,200) (5,778) – (698) – (18,676)
Hedging settlement (6,275) (4,015) – – – (10,290)
Other operating revenue – – – 204 – 204
Revenue 79,370 53,682 24,560 15,398 – 173,010
Operating costs (19,367) (29,853) (9,123) (9,896) – (68,239)
Cost of blending (33,693) (5,198) – – – (38,891)
Change in inventory position 291 248 1,331 259 – 2,129
Depletion and decommissioning 
costs (8,821) (11,773) (6,125) (3,212) – (29,931)
Exploration and business
development costs – – – – (903) (903)
Gross profit/(loss) 17,780 7,106 10,643 2,549 (903) 37,175
Three months ended – March 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 98,236 63,786 15,376 12,814 – 190,212
NGLs – 191 – – – 191
Gas 107 11,515 – – – 11,622
Net sales of oil and gas 98,343 75,492 15,376 12,814 – 202,025
Change in under/over lift position – – – 1,141 – 1,141
Royalties (13,120) (9,668) – (840) – (23,628)
Hedging settlement (843) (373) – – – (1,216)
Other operating revenue – – – 170 – 170
Revenue 84,380 65,451 15,376 13,285 – 178,492
Operating costs (19,180) (33,325) (8,581) (8,067) – (69,153)
Cost of blending (32,391) (5,335) – – – (37,726)
Change in inventory position 864 (536) 3,339 (167) – 3,500
Depletion and decommissioning 
costs (8,797) (12,302) (5,751) (2,166) – (29,016)
Depreciation of other assets – – (1,917) – – (1,917)
Exploration and business
development costs – – – – (31) (31)
Gross profit/(loss) 24,876 13,953 2,466 2,885 (31) 44,149
10

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Three months ended March 31, 2026 Review 
Revenue
Total revenue amounted to USD 173,010 thousand for Q1 2026, compared to USD 178,492 thousand for Q1 2025, and is analyzed 
as follows: 
USD Thousands 
Three months ended March 31
2026 2025
Crude oil sales 194,031 190,212
Gas and NGL sales 12,485 11,813
Change in under/overlift position (4,744) 1,141
Royalties (18,676) (23,628)
Hedging settlement (10,290) (1,216)
Other operating revenue 204 170
Total revenue 173,010 178,492
The main components of total revenue for Q1 2026, and Q1 2025, respectively, are detailed below. 
Crude oil sales
Three months ended – March 31, 2026
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 97,751 51,084 24,560 20,636 194,031
- Quantity sold in bbls 1,716,374 886,242 223,093 279,186 3,104,895
- Average price realized USD per bbl 56.95 57.64 110.09 73.91 62.49
Three months ended – March 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 98,236 63,786 15,376 12,814 190,212
- Quantity sold in bbls 1,688,646 1,082,087 195,131 169,022 3,134,886
- Average price realized USD per bbl 58.17 58.95 78.80 75.81 60.68
Crude oil revenue was 2% higher in Q1 2026 compared to Q1 2025 mainly due to higher price, especially in March 2026. France 
sales volumes are 65% higher in Q1 2026 compared to Q1 2025 as a result of the yearly lifting in Acquitaine in Q1 2026. 
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 Q1 2026, WTI averaged USD 72 per bbl compared to USD 71 per bbl for Q1 2025 and the 
average discount to WCS used in IPC’s pricing formula was USD 14 per bbl compared to USD 13 per bbl for the comparative 
period in 2025. 
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia
during Q1 2026 and one cargo lifting in Q1 2025. Produced unsold oil barrels from Bertam at the end of Q1 2026 amounted to
134,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 81 per bbl for
Q1 2026 compared to USD 76 per bbl for the comparative period.
11

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Gas and NGL sales
Three months ended – March 31, 2026
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 94 12,391 12,485
- Quantity sold in Mcf 71,289 6,691,310 6,762,599
- Average price realized USD per Mcf 1.32 1.85 1.85
Three months ended – March 31, 2025
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 107 11,706 11,813
- Quantity sold in Mcf 78,835 6,885,845 6,964,680
- Average price realized USD per Mcf 1.36 1.70 1.70
Gas and NGL sales revenue was 6% higher for the Q1 2026 compared to Q1 2025, driven by marginally higher prices.
IPC’s achieved gas price is based on AECO pricing plus a premium. For Q1 2026, IPC realized an average price of CAD 2.51 per 
Mcf compared to AECO average pricing of CAD 1.98 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 Q1 2026 amounted to a loss of USD 10,290 thousand on the oil contracts. Also see the 
Financial Position and Liquidity and the Financial Risk Management sections below.
Production costs
Production costs including inventory movements amounted to USD 105,001 thousand for Q1 2026 compared to USD 103,379 
thousand for Q1 2025 and is analyzed as follows:
Three months ended – March 31, 2026
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Operating costs1 19,367 29,853 9,123 9,896 – 68,239
USD/boe2 14.62 14.45 30.30 56.40 n/a 17.64
Cost of blending 33,693 5,198 – – – 38,891
Change in inventory position (291) (248) (1,331) (259) – (2,129)
Production costs 52,769 34,803 7,792 9,637 – 105,001
12

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Three months ended – March 31, 2025
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 19,180 33,325 11,802 8,067 (3,221) 69,153
USD/boe2 14.81 14.76 45.80 43.08 n/a 17.30
Cost of blending 32,391 5,335 – – – 37,726
Change in inventory position (864) 536 (3,339) 167 – (3,500)
Production costs 50,707 39,196 8,463 8,234 (3,221) 103,379
1  See definition on page 15 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 2025.
3   Up to April 2025, 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 33.30 for Q1 2025.
Operating costs
Operating costs amounted to USD 68,239 thousand for Q1 2026 compared to USD 69,153 thousand for Q1 2025. Operating costs 
per boe amounted to USD 17.64 per boe in Q1 2026 slightly below the guidance for the quarter and compared with USD 17.30 per 
boe in Q1 2025.
Cost of blending
For the Suffield area and Onion Lake Thermal assets in Canada, oil production is blended with purchased diluent to meet pipeline 
specifications. As a result of the blending, actual sales volumes are higher than produced barrels and the realized sales price of a 
blended barrel is higher than an unblended barrel.
The cost of the diluent amounted to USD 38,891 thousand for Q1 2026 compared to USD 37,726 thousand for Q1 2025. 
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 Q1 2026, IPC had crude entitlement of 134,000 bbls of oil on the FPSO Bertam facility 
being crude produced but not yet sold. 
Depletion costs
The total depletion of oil and gas properties amounted to USD 29,931 thousand for Q1 2026 compared to USD 29,016 thousand 
for Q1 2025.
The depletion charge is analyzed in the following tables:
Three months ended – March 31, 2026
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 8,821 11,773 6,125 3,212 29,931
USD per boe2 6.66 5.70 20.34 18.31 7.74
Three months ended – March 31, 2025
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 8,797 12,302 5,751 2,166 29,016
USD per boe2 6.79 5.45 22.32 11.57 7.26
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. 
Depreciation of other tangible fixed assets
The total depreciation of other tangible fixed assets amounted to nil for Q1 2026 compared to USD 1,917 thousand for Q1 2025. In 
2025, the depreciation relates to FPSO Bertam, which has been depreciated to its residual value by the end of 2025.
13

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Exploration and business development costs
The total exploration and business developments costs amounted to a cost of USD 903 thousand for Q1 2026.
Net financial items
Net financial items amounted to a charge of USD 20,737 thousand for Q1 2026, compared to a charge of USD 18,855 thousand for
Q1 2025, and included a net foreign exchange loss of USD 6,268 thousand and no realized currency hedge loss for Q1 2026 
compared to a realized currency hedge loss and a net foreign exchange gain of respectively USD 6,858 thousand and USD 18 
thousand for Q1 2025. The foreign exchange movements are mainly resulting from the revaluation of intra-group loan funding 
balances.
Excluding foreign exchange movements and realized currency cashflow hedges, the net financial items amounted to a charge of
USD 14,469 thousand for Q1 2026, compared to a charge of USD 12,015 thousand for Q1 2025.
The interest expense amounted to USD 9,560 thousand for Q1 2026, compared to USD 8,761 thousand for the comparative period
in 2025, mainly related to the bond interest at a fixed coupon rate of 7.5% per annum (former bonds in 2025 were bearing a fixed 
coupon rate of 7.25% per annum). Interest income generated on cash balances held amounted to USD 125 thousand for Q1 2026 
and USD 1,634 thousand for Q1 2025.
The unwinding of the asset retirement obligation discount rate amounted to USD 4,162 thousand for Q1 2026 compared to USD
3,957 thousand for Q1 2025. 
Income tax
The corporate income tax amounted to a charge of USD 3,386 thousand for Q1 2026 compared to a charge of USD 4,679 
thousand for Q1 2025.
The current income tax amounted to a charge of USD 456 thousand for Q1 2026 and a charge of USD 514 thousand for Q1 2025 
and mainly related to France. No corporate income tax is expected to be payable in Canada in 2026 due to the usage of historical 
tax pools. 
Capital Expenditure
Development and exploration and evaluation expenditures incurred during the quarter ended March 31, 2026 was as follows:
USD Thousands
Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 66,269 1,459 561 671 68,960
Exploration and evaluation 1,701 – – – 1,701
67,970 1,459 561 671 70,661
Capital expenditures of USD 70,661 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 11,186 thousand as at March 31, 2026, which included USD 9,200 thousand in 
respect of the FPSO Bertam. The FPSO Bertam has been depreciated to its residual value.
Financial Position and Liquidity
Financing 
As at January 1, 2025, IPC had USD 450 million of senior unsecured bonds outstanding, maturing in February 2027 with a fixed 
coupon rate of 7.25% per annum. In October 2025, IPC completed the issuance of USD 450 million of new senior unsecured 
bonds, maturing in October 2030 with a fixed coupon rate of 7.50% per annum, payable in semi-annual instalments in April and 
October, and with semi-annual amortizations of USD 25 million commencing in April 2028. The proceeds of the new bonds were 
used to fully redeem and cancel the previous bonds.
The bond repayment obligations as at March 31, 2026, are classified as non-current as there are no mandatory repayments within 
the next twelve months.
In addition, as at March 31, 2026, 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 March 31, 2026, CAD 104 million 
(approximately USD 74 million) was drawn under the Canadian RCF . In April 2026, the Group amended and extended the Canadian 
RCF , increasing the committed facility size to CAD 348.5 million and extending the maturity to May 2028. As at March 31, 2026, 
the Group also had a letter of credit facility in Canada (the “LC Facility”). As at March 31, 2026, operational letters of credit in an 
aggregate of CAD 11.9 million have been issued under the LC Facility.
14

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
As at March 31, 2026, IPC had an unsecured Euro credit facility in France (the “France Facility“) which will be fully repaid in May
2026. The  outstanding under the France Facility as at March 31, 2026 was USD 1 million (EUR 0.8 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 March 31, 2026.
Net debt as at March 31, 2026 amounted to USD 513 million. Cash and cash equivalents held amounted to USD 12 million as at 
March 31, 2026.
IPC intends to fund the budgeted capital expenditures in 2026 with forecast cash flow generated by its operations, cash on hand 
and Canadian RCF loan drawing.
Working Capital 
As at March 31, 2026, the Group had a working capital balance including cash of negative USD 44,956 thousand compared to 
negative USD 29,946 thousand as at December 31, 2025. The difference is mainly a result of the decreased cash following capital 
expenditures on the Blackrod Phase 1 development project.
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 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 March 31
2026 2025
Revenue 173,010 178,492 
Production costs and net sales of diluent to third party1 (104,819) (103,188)
Current tax (456) (514)
Operating cash flow 67,735 74,790 
1 Includes net sales of diluent to third party amounting to USD 182 thousand for the first quarter of 2026.
15

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Free cash flow
The following table sets out how free cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended March 31
2026 2025
Operating cash flow - see above  67,735 74,790 
Capital expenditures  (70,661) (98,886)
Abandonment and farm-in expenditures1  (472) (321)
General and administrative expenses before depreciation2  (3,902) (4,358)
Cash financial items3  (9,786) (14,397)
Free cash flow  (17,086) (43,172)
1  See note 15 to the Financial Statements. 
2  Depreciation is not specifically disclosed in the Financial Statements.
3  See note 4 to the Financial Statements.
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended March 31
2026 2025
Net result 12,762 16,231 
Net financial items 20,737 18,855 
Income tax 3,386 4,679 
Depletion and decommissioning costs 29,931 29,016 
Depreciation of other tangible fixed assets – 1,917 
Exploration and business development costs 903 31 
Sale of assets1 (3,793) (94)
Depreciation included in general and administrative expenses2 363 311 
EBITDA 64,289 70,946 
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 March 31
2026 2025
Production costs 105,001 103,379 
Cost of blending (38,891) (37,726)
Change in inventory position 2,129 3,500 
Operating costs 68,239 69,153 
16

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Management’s Discussion and Analysis
For the three months ended March 31, 2026
Net cash/(debt)
The following table sets out how net cash/(debt) is calculated: 
USD Thousands March 31, 2026 December 31, 2025
Bank loans (75,230) (40,652)
Bonds (450,000) (450,000)
Cash and cash equivalents 11,817 7,037
Net cash/(debt) (513,413) (483,615)
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, had issued five letters of credit as at March 31, 2026 as follows: (a) MCAD 1.0 in 
respect of its obligations related to the Ferguson asset; (b) MCAD 1.3 in respect of pipeline access; (c) MCAD 0.5 in respect of the 
hedging of electricity prices; (d) MCAD 3.9 in respect of electricity distribution services; and (e) MCAD 5.3 in respect of the land 
acquisition completed in October 2025.
Outstanding Share Data 
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2025, IPC had a total of 119,169,471 common shares issued and outstanding and held 110,156 common shares 
held in treasury.
Over the period of January 1, 2025 to December 4, 2025, IPC purchased and cancelled 6,641,970 common shares under the 
normal course issuer bid (NCIB) and 261,818 common shares under certain other exemptions in Canada.
As at December 31, 2025, IPC had a total of 112,155,527 common shares issued and outstanding, with no common shares held in 
treasury.
In February 2026, IPC issued 671,225 common shares in connection with the vesting of previously issued IPC Share Unit Plan 
awards. As at March 31, 2026 and May 5, 2026, IPC had a total of 112,826,752 common shares issued and outstanding, with no 
common shares held in treasury.
Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 42,597,533 
common shares in IPC, representing 37.8% of the outstanding common shares as at March 31, 2026.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares.
IPC has 2,541,095 IPC Share Unit Plan awards outstanding as at May 5, 2026 of which 788,036 awards were granted in 2026.
The Corporation is authorized to issue an unlimited number of common shares without par value. The Corporation is also 
authorized to issue an unlimited number of class A preferred shares and an unlimited number of class B preferred shares, issuable 
in series.
Contractual Obligations and Commitments 
In the normal course of business, the Group has committed to certain payments which are not recognized as liabilities. The 
following table summarizes the Group’s commitments in Canada as at March 31, 2026: 
MCAD 2026 2027 2028 2029 2030 Thereafter
Transportation service1 45.8 83.8 99.5 100.8 101.7 1,355.0
Power2 9.3 12.4 9.8 – – –
Total commitments 55.1 96.2 109.3 100.8 101.7 1,355.0
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2046.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from April 1, 2026 to December
31, 2028, and an additional 5MWh at a weighted average price of CAD 58.31/MWh from April 1, 2026 to December 31, 2027.
17

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Management’s Discussion and Analysis
For the three months ended March 31, 2026
Material Accounting Policies and Estimates
In connection with the preparation of the Corporation’s consolidated financial statements, management has made assumptions 
and estimates about future events and applied judgments that affect the reported values of assets, liabilities, revenues, expenses 
and related disclosures. These assumptions, estimates and judgments are based on historical experience, current trends and other 
factors that they believe to be relevant at the time the financial statements are prepared. The management reviews the accounting 
policies, assumptions, estimates and judgments to ensure that the financial statements are presented fairly in accordance with 
IFRS. However, because future events and their effects cannot be determined with certainty, actual results could differ from these 
assumptions and estimates, and such differences could be material.
Management believes the following critical accounting policies affect the more significant judgments and estimates used in the 
preparation of the consolidated financial statements:
Oil and gas reserves, impairment and asset retirement obligations
The accounting for oil and gas assets requires significant estimates and judgements, particularly in relation to reserves, impairment 
and asset retirement obligations. Estimates of proved and probable oil and gas reserves, prepared using standard recognized 
evaluation techniques and reviewed by independent qualified reserves auditors, are fundamental to impairment testing, 
depletion calculations under the unit of production method, and the timing and measurement of asset retirement obligations. 
These estimates are based on management’s assumptions regarding expected production volumes, future oil and gas prices, 
development and production costs, and economic factors as such oil price and inflation.
Impairment tests are performed when there are indicators of impairment. Key assumptions in the impairment models include oil 
and gas reserve estimates, forward price curves, long-term cost assumptions and the discount rate, all of which are subject to 
change as new information becomes available or economic conditions evolve.
Provisions for asset retirement obligations are based on estimates of future decommissioning and restoration costs, reflecting 
current legal and constructive requirements, available technology and prevailing price levels. Actual cash outflows may differ from 
estimates due to changes in legislation, technical requirements or cost levels, and therefore these provisions are reviewed on a 
regular basis.
Deferred income tax assets
The Group accounts for differences that arise between the carrying amount of assets and liabilities and their tax bases in 
accordance with IAS 12, Income Taxes, which requires deferred income tax assets only to be recognized to the extent that 
is probable that future taxable profits will be available against which the temporary differences can be utilized. Management 
estimates future taxable profits based on the financial models used to value its oil and gas properties. Any change to the estimates 
and assumptions used for the key operational and financial variables used within the business models could affect the amount of 
deferred income tax assets recognized.
The effects of changes in estimates do not give rise to prior year adjustments and are treated prospectively over the estimated 
remaining commercial reserves of each field. While the Group uses its best estimates and judgement, actual results could differ 
from these estimates.
Transactions with Related Parties 
The Group recognizes the following related parties: associated companies, jointly controlled entities, key management personnel 
and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or 
of its family or of any individual that controls, or has joint control or significant influence over the entity.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with 
parties at arm’s length.
During the first quarter of 2026, 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 March 31, 2026, the Group had entered into oil, gas and electricity  
hedges – see below.
Management believes that the cash resources, other current assets and cash flow from operations are sufficient to finance the 
Group’s operations and capital expenditures program over the next year.
18

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Management’s Discussion and Analysis
For the three months ended March 31, 2026
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 March 31, 2026, which are summarized as follows:
Period Volume (barrels per 
day) Type Average Pricing 
April 1, 2026 - June 30, 2026 9,000 WTI Sale Swap USD 62.36/bbl
April 1, 2026 - December 31, 2026 5,000 WTI/WCS Differential USD -12.50/bbl
July 1, 2026 - December 31, 2027 5,000 WCS (Hardisty vs Houston)1 USD -7.55/bbl
July 1, 2026 - December 31, 2026 2,000 ARV2 USD -3.65/bbl
April 1, 2026 - June 30, 2026 2,000 Brent Sale Swap USD 68.06/bbl
1 Represents the cost of transporting a barrel of WCS quality from Hardisty to Houston.
2 Represents the difference in USD of a barrel of WCS in Houston against a barrel of WTI quality.
The Group had gas price sale financial hedges outstanding as at March 31, 2026, which are summarized as follows:
Period Volume (Gigajoules (GJ) per
day)) Type Average Pricing 
April 1, 2026 - October 31, 2026 15,000 AECO Gas Swap CAD 2.73/GJ
The Group had electricity financial hedges outstanding as at March 31, 2026, which are summarized as follows:
Period Volume (MWh) Type Average Pricing 
April 1, 2026 - September 30, 2040 3 AESO CAD 75.00/MWh
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had 
a negative fair value of USD 28,010 thousand as at March 31, 2026.
Currency Risk
The Group’s policy on currency rate hedging is, in the case of currency exposure, to consider fixing the rate of exchange. The 
Group will take into account the currency exposure, current rates of exchange and market expectations in comparison to historic 
trends and volatility in making the decision to hedge.
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.
19

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Management’s Discussion and Analysis
For the three months ended March 31, 2026
The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take 
possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In 
addition, cash is to be held and transacted only through major banks.
RISK FACTORS 
IPC is engaged in the exploration, development and production of oil and gas and its operations are subject to various risks and 
uncertainties which include, but are not limited to, those listed below. For further information and discussion of these risks and 
uncertainties, please see IPC’s Annual Information Form for the year ended December 31, 2025 (”AIF”) available on SEDAR+ at 
www.sedarplus.ca or on IPC’s website at www.international-petroleum.com. See also “Cautionary Statement Regarding Forward-
Looking Information” and “Reserves and Resources Advisory” below.
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be 
disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation 
is recorded, processed, summarized and reported within the time periods specified in the securities legislation. Management, 
under the supervision of the Chief Executive Officer and the Chief Financial Officer, is responsible for the design and operation of 
disclosure controls and procedures.
Internal Controls over Financial Reporting
Management is also responsible for the design of the Group’s internal controls over financial reporting in order to provide reasonable 
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in 
accordance with IFRS. However, due to inherent limitations, internal control over financial reporting may not prevent or detect all 
misstatements and fraud.
There have been no material changes to the Groups internal control over financial reporting during the three months ended March 31, 
2026, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial reporting. 
Control Framework 
Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control
– Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission 
(COSO). Management concluded that the Corporation’s internal control over financial reporting was effective as of March  31, 2026.  
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 
This MD&A contains statements and information which constitute “forward-looking statements“ or “forward-looking information“ 
(within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements“) 
relate to future events, including the Corporation’s future performance, business prospects or opportunities. Actual results may differ 
materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this MD&A 
are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this MD&A, unless 
otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except 
as required by applicable laws.
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“.
20

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
Forward-looking statements include, but are not limited to, statements with respect to: 
• 2026 production ranges (including total daily average production), production composition, cash flows, operating costs and 
capital and decommissioning expenditure estimates;
• Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business 
plans and assumptions regarding the business environment, which are subject to change;
• IPC’s financial and operational flexibility to navigate the Corporation through periods of volatile commodity prices;
• The ability to fully fund IPC’s future expenditures from cash flows and current borrowing capacity;
• IPC’s intention and ability to continue to implement its strategies to build long-term shareholder value;
• The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth;
• The continued facility uptime and reservoir performance in IPC’s areas of operation;
• Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing, 
regulatory approvals, third party commercial arrangements, breakeven oil prices, net present values and futur phase 
developments;
• 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 of IPC to maintain current and forecast production in France and Malaysia;
• The intention and ability of IPC to acquire common shares under the NCIB, including the timing of any such purchases;
• The return of value to IPC’s shareholders as a result of the NCIB;
• IPC’s ability to implement its greenhouse gas (GHG) emissions intensity and climate strategies and to achieve its net GHG 
emissions intensity reduction targets;
• IPC’s ability to implement projects to reduce net GHG emissions intensity, including potential carbon capture and storage;
• Estimates of reserves and contingent resources;
• The ability to generate free cash flows and use that cash to repay debt;
• IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the 
Corporation;
• IPC’s ability to identify and complete future acquisitions;
• Expectations regarding the oil and gas industry in Canada, Malaysia and France, including assumptions regarding future 
royalty rates, regulatory approvals, legislative changes, tariffs, and ongoing projects and their expected completion; and
• Future drilling and other exploration and development activities.
Statements relating to “reserves“ and “contingent resources“ are also deemed to be forward-looking statements, as they involve 
the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the 
quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery 
of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of 
management. See also “Reserves and Resources Advisory“.
The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations
and assumptions concerning: the duration and impact of tariffs that are currently in effect on goods exported from or imported 
into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of 
such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the 
other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of 
products from one country to the other, including on oil and natural gas; prevailing commodity prices and currency exchange rates; 
applicable royalty rates and tax laws; interest rates; future well production rates and reserve and contingent resource volumes; 
operating costs; IPC’s ability to maintain its existing credit ratings; IPC’s ability to achieve its performance targets; the timing of 
receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing 
and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, 
location and extent of future drilling operations; the successful completion of acquisitions and dispositions and that IPC will be able 
to implement its standards, controls, procedures and policies in respect of any acquisitions and realize the expected synergies on 
the anticipated timeline or at all; the benefits of acquisitions; the state of the economy and the exploration and production business 
in the jurisdictions in which IPC operates and globally; the availability and cost of financing, labour and services; IPC’s intention 
to complete share repurchases under the normal course issuer bid program, including the funding of such share repurchases, 
existing and future market conditions, including with respect to the price of IPC’s common shares, and compliance with respect to 
applicable limitations under securities laws and regulations and stock exchange policies; and the ability to market crude oil, natural 
gas and natural gas liquids successfully.
Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are 
reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they 
will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve 
inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors 
and risks.
21

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
These include, but are not limited to: 
• General global economic, market and business conditions;
• The risks associated with the oil and gas industry in general such as operational risks in development, exploration and 
production;
• Delays or changes in plans with respect to exploration or development projects or capital expenditures;
• The uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses;
• Health, safety and environmental risks;
• Commodity price fluctuations;
• Interest rate and exchange rate fluctuations;
• Marketing and transportation;
• Loss of markets;
• Environmental and climate-related risks;
• Competition;
• Innovation and cybersecurity risks related to IPC’s systems, including costs of addressing or mitigating such risks;
• The ability to attract, engage and retain skilled employees;
• Incorrect assessment of the value of acquisitions;
• Failure to complete or realize the anticipated benefits of acquisitions or dispositions;
• The ability to access sufficient capital from internal and external sources;
• Failure to obtain required regulatory and other approvals;
• Geopolitical conflicts, including current and potential future conflicts in Ukraine, the Middle East, South America and 
elsewhere and their potential impact on, among other things, global market conditions;
• Political or economic developments, including, without limitation, the risk that (i) the tariffs that are currently in effect 
on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have 
been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are 
increased, or new tariffs are imposed, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of 
tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural 
gas, and (iii) the tariffs imposed or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or 
threatened to be imposed by other countries on the U.S. will trigger a broader global trade war which could have a material 
adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and 
the Corporation, including by decreasing demand for, and the price of oil, and natural gas, disrupting supply chains, increasing 
costs, causing volatility in the global financial markets, and limiting access to financing; and
• Changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations. 
Readers are cautioned that the foregoing list of factors is not exhaustive. See also “Risk Factors”.
Estimated production and FCF generation are based on IPC’s current business plans over the periods of 2026 to 2030 and 2031 
to 2035, less net debt of USD 484 million as at December 31, 2025, with assumptions based on the reports of IPC’s independent 
reserves evaluator and auditor, and including certain corporate adjustments relating to estimated general and administration costs 
and hedging, and excluding shareholder distributions and certain refinancing costs. Assumptions include average net production 
of approximately 62 Mboepd over the period of 2026 to 2030, average capital expenditures of approximately USD 5 per boe, 
average operating costs of approximately USD 18 to 20 per boe, average Brent oil prices of USD 65 to 95 per bbl escalating by 2% 
per year, and average Brent to Western Canadian Select differentials and average gas prices as estimated by IPC’s independent 
reserves evaluator and auditor and as further described in the AIF . IPC’s current business plans and assumptions, and the business 
environment, are subject to change. Actual results may differ materially from forward-looking estimates and forecasts.
Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the 
Financial Statements, the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2025 (see “Cautionary 
Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk Factors”) and other reports 
on file with applicable securities regulatory authorities, including previous financial reports, management’s discussion and analysis 
and material change reports, which may be accessed through the SEDAR+ website (www.sedarplus.ca) or IPC’s website (www. 
international-petroleum.com).
Management of IPC approved the production, operating costs, operating cash flow, capital and decommissioning expenditures 
and free cash flow guidance and estimates contained herein as of the date of this MD&A. The purpose of these guidance and 
estimates is to assist readers in understanding IPC’s expected and targeted financial results, and this information may not be 
appropriate for other purposes.
22

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

Management’s Discussion and Analysis
For the three months ended March 31, 2026
RESERVES AND RESOURCES ADVISORY 
This MD&A contains references to estimates of gross and net reserves and resources attributed to the Corporation’s oil and gas 
assets. Gross reserves/resources are the working interest (operating or non-operating) share before deduction of royalties and 
without including any royalty interests. Net reserves/resources are the working interest (operating or non-operating) share after 
deduction of royalty obligations, plus royalty interests in reserves/resources, and in respect of PSCs in Malaysia, adjusted for cost 
and profit oil. Unless otherwise indicated, reserves/resource volumes are presented on a gross basis.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets 
in Canada and France/Malaysia are effective as of December 31, 2025, and are included in the reports prepared by Sproule 
International Limited and ERC Equipoise Ltd., respectively (collectively, Sproule ERCE), an independent qualified reserves evaluator 
and auditor, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the 
Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule ERCE’s December 31, 2025 price forecasts.
The price forecasts used in the Sproule ERCE reports, are available on the website of Sproule ERCE (sproule-erce.com) and are 
contained in the AIF . These price forecasts are as at December 31, 2025 and may not be reflective of current and future forecast 
commodity prices.
The reserve life index (RLI) is calculated by dividing the 2P reserves of 521 MMboe as at December 31, 2025, by the mid-point of 
the 2026 CMD production guidance of 44,000 to 47,000 boepd.
The product types comprising the 2P reserves and contingent resources described in this MD&A are contained in the AIF . See also 
“Supplemental Information regarding Product Types” below. Light, medium and heavy crude oil and bitumen reserves/ resources 
disclosed in this MD&A include solution gas and other by-products.
“2P reserves“ means proved plus probable reserves. “Proved reserves“ are those reserves that can be estimated with a high 
degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved 
reserves. “Probable reserves“ are those additional reserves that are less certain to be recovered than proved reserves. It is equally 
likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable 
reserves.
Each of the reserves categories reported (proved and probable) may be divided into developed and undeveloped categories. 
“Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if 
facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) 
to put the reserves on production. The developed category may be subdivided into producing and non-producing. “Developed 
producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the 
estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of 
resumption of production must be known with reasonable certainty. “Developed non-producing reserves” are those reserves that 
either have not been on production, or have previously been on production, but are shut-in, and the date of resumption
of production is unknown. “Undeveloped reserves” are those reserves expected to be recovered from known accumulations 
where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of 
production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known 
accumulations using established technology or technology under development, but which are not currently considered to be 
commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion 
of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be 
resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political, 
and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered 
recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in
accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or 
characterized by their economic status.
There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a 
classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity 
that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best 
estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered 
will equal or exceed the best estimate.
Contingent resources are further classified based on project maturity. The project maturity subclasses include development 
pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources 
are classified as either development on hold or development unclarified. Development on hold is defined as a contingent
resource where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved 
that are usually beyond the control of the operator. Development unclarified is defined as a contingent resource that requires 
further appraisal to clarify the potential for development and has been assigned a lower chance of development until commercial 
contingencies can be clearly defined. Chance of development is the probability of a project being commercially viable. Where 
risked resources are presented, they have been adjusted based on the chance of development by multiplying the unrisked values 
by the chance of development.
 
23

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Management’s Discussion and Analysis
For the three months ended March 31, 2026
References to “unrisked“ contingent resources volumes means that the reported volumes of contingent resources have not 
been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook for 
contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies 
required for the re-classification of the contingent resources as reserves being resolved. Therefore, unrisked reported volumes 
of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such 
resources.
The contingent resources reported in this MD&A are estimates only. The estimates are based upon a number of factors and 
assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and 
commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil 
and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks 
and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There 
is uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this MD&A. 
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.
2P reserves and contingent resources included in the reports prepared by Sproule ERCE have been aggregated. Estimates of 
reserves, resources and future net revenue for individual properties may not reflect the same level of confidence as estimates 
of reserves, resources and future net revenue for all properties, due to aggregation. This MD&A contains estimates of the net 
present value of the future net revenue from IPC’s reserves and contingent resources. The estimated values of future net revenue 
disclosed in this MD&A do not represent fair market value. There is no assurance that the forecast prices and cost assumptions 
used in the reserves and resources evaluations will be attained and variances could be material.
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
March 31, 2026 22.4 6.3 85.7 MMcf                     
(14.3 Mboe) 43.0
March 31, 2025 23.2 6.5 88.2 MMcf                     
(14.7 Mboe) 44.4
Year ended December 31, 2025
December 31, 2025
23.6 6.4 89.6MMcf                     
(14.9 Mboe) 44.9
This MD&A also makes reference to IPC’s forecast total average daily production of 44,000 to 47,000 boepd for 2026. IPC 
estimates that approximately 57% of that production will be comprised of heavy crude oil, approximately 12% will be comprised 
of light and medium crude oil and approximately 31% will be comprised of conventional natural gas.
24

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Management’s Discussion and Analysis
For the three months ended March 31, 2026
OTHER SUPPLEMENTARY INFORMATION
Currency Abbreviations
CAD  Canadian dollar
MCAD  Million Canadian dollar
EUR  Euro
MEUR  Million Euro
USD  US dollar
MUSD  Million US dollar
MYR  Malaysian Ringgit
MMYR  Million Malaysian Ringgit
Oil related terms and measurements
AECO   The daily average benchmark price for natural gas at the AECO hub in southeast Alberta                                                                            
AESO  Alberta Electric System Operator
API   An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale
ARV  Argus WCS Houston (represents the differential, in USD, between a barrel of WCS quality in Houston and WTI)
ASP   Alkaline surfactant polymer (an EOR process)
bbl   Barrel (1 barrel = 159 litres)
boe   Barrels of oil equivalents
boepd   Barrels of oil equivalents per day
bopd   Barrels of oil per day
Bcf  Billion cubic feet
C5  Condensate
CO2e  Carbon dioxide equivalents, including carbon dioxide, methane and nitrous oxide
Empress   The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border
EOR   Enhanced Oil Recovery
FPSO  Floating Production Storage and Offloading (facility)
GJ  Gigajoules
Mbbl   Thousand barrels
MMbbl   Million barrels
Mboe   Thousand barrels of oil equivalents 
Mboepd   Thousand barrels of oil equivalents per day
Mbopd   Thousand barrels of oil per day
MMboe   Million barrels of oil equivalents
MMbtu   Million British thermal units
Mcf   Thousand cubic feet
Mcfpd  Thousand cubic feet per day
MMcf   Million cubic feet
MW  Mega watt
MWh  Mega watt per hour
NGL   Natural gas liquid
SAGD   Steam assisted gravity drainage
WTI   West Texas Intermediate
WCS   Western Canadian Select
25

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Management’s Discussion and Analysis
For the three months ended March 31, 2026
DIRECTORS
C. Ashley Heppenstall
Director, Chair
London, England
William Lundin
Director, President and Chief Executive Officer
Coppet, Switzerland
Chris Bruijnzeels
Director
Abcoude, The Netherlands
Donald K. Charter
Director
Toronto, Ontario, Canada
Lukas (Harry) H. Lundin
Director
Toronto, Ontario, Canada
Emily Moore
Director
Toronto, Ontario, Canada
Mike Nicholson
Director
Monaco
Deborah Starkman
Director
Toronto, Ontario, Canada
OFFICERS
William Lundin
President and Chief Executive Officer
Coppet, Switzerland
Christophe Nerguararian
Chief Financial Officer
Geneva, Switzerland
Nicki Duncan
Chief Operating Officer
Geneva, Switzerland
Jeffrey Fountain
General Counsel and Corporate Secretary
Geneva, Switzerland
Rebecca Gordon
Senior Vice President Corporate Planning and 
Investor Relations
Geneva, Switzerland 
Chris Hogue
Senior Vice President Canada
Calgary, Alberta, Canada
Ryan Adair
Vice President Asset Management and
Corporate Planning Canada
Calgary, Alberta, Canada
Curtis White
Vice President Commercial Canada
Calgary, Alberta, Canada
MEDIA AND INVESTOR RELATIONS
Robert Eriksson 
Stockholm, Sweden
CORPORATE OFFICE
Suite 2800, 1055 Dunsmuir Street Vancouver, 
British Columbia
V7X 1L2 Canada
Telephone: +1 604 689 7842
Website: www.international-petroleum.com
OPERATIONS OFFICE
5 Chemin de la Pallanterie
1222 Vésenaz
Switzerland
Telephone: +41 22 595 10 50
E-mail: info@international-petroleum.com
REGISTERED AND RECORDS OFFICE
Suite 3500, 1133 Melville Street 
Vancouver, British Columbia
V6E 4E5 Canada
INDEPENDENT AUDITORS
PricewaterhouseCoopers LLP , Canada
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta, and Toronto, Ontario
STOCK EXCHANGE LISTINGS
Toronto Stock Exchange and NASDAQ Stockholm 
Trading Symbol: IPCO
26

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