Kvartalsrapport Q1 2025

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

Q1
International Petroleum Corporation
Interim Condensed Consolidated 
Financial Statements
For the three months ended March 31, 2025

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

2
Contents
Interim Condensed Consolidated Statement of Operations  3
Interim Condensed Consolidated Statement of Comprehensive Income/(Loss)  4
Interim Condensed Consolidated Balance Sheet  5
Interim Condensed Consolidated Statement of Cash Flow 6
Interim Condensed Consolidated Statement of Changes in Equity 7
Notes to the Interim Condensed Consolidated Financial Statements 8
Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

3
Interim Condensed Consolidated Statement of Operations
For the three months ended March 31, 2025 and 2024, UNAUDITED
Three months ended March 31
USD Thousands Note 2025 2024
Revenue 2 178,492 206,419
Cost of sales
Production costs 3 (103,379) (115,745)
Depletion and decommissioning costs 8 (29,016) (33,153)
Depreciation of other tangible fixed assets 8 (1,917) (2,262)
Exploration and business development costs 7 (31) (75)
Gross profit 2 44,149 55,184
Other income/(expense) 285 -
General, administration and depreciation expenses (4,669) (3,949)
Profit before financial items 39,765 51,235
Finance income 4 1,652 5,617
Finance costs 5 (20,507) (15,387)
Net financial items (18,855) (9,770)
Profit before tax 20,910 41,465
Income tax expense 6 (4,679) (7,746)
Net result 16,231 33,719
Net result attributable to:
Shareholders of the Parent Company 16,229 33,712
Non-controlling interest 2 7 
16,231 33,719
Earnings per share – USD1 14 0.14 0.27
Earnings per share fully diluted – USD1 14 0.13 0.26
1  Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the interim condensed consolidated financial statements

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

4
Interim Condensed Consolidated Statement of Comprehensive Income/(Loss)
For the three months ended March 31, 2025 and 2024, UNAUDITED
Three months ended March 31
USD Thousands Note 2025 2024
Net result 16,231 33,719
Other comprehensive income/(loss)
Items that may be reclassified to profit or loss:
Gain/(loss) on cash flow hedges 1,721 (45,419)
Reclassification of hedging (gains)/losses to profit or 
loss    222 1,216 (9,206)
Income tax relating to these items (702) 13,003
Currency translation adjustments 3,946 (22,372)
Total comprehensive income/(loss) 22,412 (30,275)
Total comprehensive income attributable to:
Shareholders of the Parent Company 22,407 (30,277)
Non-controlling interest 5 2
22,412 (30,275)
See accompanying notes to the interim condensed consolidated financial statements

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

5
Interim Condensed Consolidated Balance Sheet
As at March 31, 2025 and December 31 2024, UNAUDITED
USD Thousands Note March 31, 2025 December 31, 2024
ASSETS
Non-current assets
Exploration and evaluation assets 7 2,297 480
Property, Plant and Equipment 8 1,572,638 1,500,912
Right-of-use assets 2,888 3,103
Deferred tax assets 6 889 1,673
Other non-current assets 9 48,691 48,665
Total non-current assets 1,627,403 1,554,833
Current assets
Inventories 10 25,026 20,073
Trade and other receivables 11 105,389 127,450
Derivative instruments 18 377 3,219
Current tax receivables 2,626 1,514
Cash and cash equivalents 12 140,194 246,593
Total current assets 273,612 398,849
TOTAL ASSETS 1,901,015 1,953,682
LIABILITIES
Non-current liabilities
Financial liabilities 15 900 1,719
Bonds 15 441,057 439,862
Lease liabilities 2,379 2,728
Provisions 16 272,636 268,509
Deferred tax liabilities 6 98,848 92,754
Derivative instruments 18 1,530 562
Total non-current liabilities 817,350 806,134
Current liabilities
Trade and other payables 17 165,083 176,371
Financial liabilities 18 3,549 3,402
Derivative instruments 18 13,146 19,869
Current tax liabilities 402 1,146
Lease liabilities 761 573
Provisions 16 6,941 6,717
Total current liabilities 189,882 208,078
EQUITY
Shareholders’ equity 893,623 939,315
Non-controlling interest 160 155
Net shareholders’ equity 893,783 939,470
TOTAL EQUITY AND LIABILITIES 1,901,015 1,953,682
Approved by the Board of Directors
(Signed) C. Ashley Heppenstall    (Signed) William Lundin
Director       Director
See accompanying notes to the interim condensed consolidated financial statements

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

6
Interim Condensed Consolidated Statement of Cash Flow
For the three months ended March 31, 2025 and 2024, UNAUDITED
Three months ended March 31
USD Thousands Note 2025 2024
Cash flow from operating activities
Net result 16,231 33,719 
Depletion, depreciation and amortization 2,8 31,244 35,710 
Income tax 6 4,679 7,746
Amortization of capitalized financing fees 5 519 510
Foreign currency exchange loss/(gain) 4,5 (18) 2,061 
Interest income 4 (1,634) (5,617)
Interest expense 5 8,761 8,818
Unwinding of asset retirement obligation discount 3,957 3,618
Share-based costs 2,261 1,934
Changes in working capital (2,289) (48,960)
Decommissioning costs paid 16 (321) (122)
Other payments 16 (703) (504)
Net income taxes paid (2,134) (3,465)
Interest received 2,142 5,011
Interest paid (16,351) (16,366)
Other 245 186
Net cash flow from operating activities 46,589 24,279
Cash flow used in investing activities
Investment in oil and gas properties 8 (98,886) (125,256)
Investment in other tangible fixed assets 8 (28) (55)
Net cash (outflow) from investing activities (98,914) (125,311)
Cash flow from financing activities
Repayments 15 (672) (1,069)
Repurchase of own shares (“NCIB”) 13 (53,187) (17,308)
Other payments (218) (223)
Net cash (outflow) from financing activities (54,077) (18,600)
Change in cash and cash equivalents (106,402) (119,632)
Cash and cash equivalents at the beginning of the 
period 246,593 517,074
Currency exchange difference in cash and cash 
equivalents 3 (52)
Cash and cash equivalents at the end of the period 140,194 397,390
   
See accompanying notes to the interim condensed consolidated financial statements

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

7
Interim Condensed Consolidated Statement of Changes in Equity
For the three months ended March 31, 2025 and 2024, UNAUDITED
USD Thousands
Share 
capital and 
premium
Retained 
earnings CTA IFRS 2 
reserve
MTM 
reserve
Pension 
reserve Total
Non-
controlling 
interest
Total
equity
Balance at January 1, 2025 141,173 875,952 (81,192) 18,092 (13,138) (1,572) 939,315 155 939,470
Net result – 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 shares 
(NCIB)1 (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 13
2 The third instalment of IPC RSP 2022 awards, the second instalment of IPC RSP 2023 awards, the first instalment of IPC RSP 2024 awards and 
the IPC PSP 2022 awards vested on February 1, 2025, at a price of CAD 18.89 per award. The difference between the value at vesting date and 
at grant (respectively CAD 9.09 per award, CAD 14.24 per award, CAD 14.82 per award and CAD 8.40 per award) was offset against retained 
earnings. 
USD Thousands
Share 
capital and 
premium
Retained 
earnings CTA IFRS 2 
reserve
MTM 
reserve
Pension 
reserve Total
Non-
controlling 
interest
Total
equity
Balance at January 1, 2024 243,361 795,490 (10,745) 18,838 31,344 1,786 1,080,074 185 1,080,259
Net result – 102,202 – – – – 102,202 17 102,219
Re-measurements on defined
pension plan – – – – – (3,491) (3,491) – (3,491)
Cash flow hedges – – – – (44,115) – (44,115) – (44,115)
Currency translation difference – – (70,447) (3,244) (367) 133 (73,925) (6) (73,931)
Total comprehensive income – 102,202 (70,447) (3,244) (44,482) (3,358) (19,329) 11 (19,318)
Repurchase of own shares 
(NCIB)1 (102,188) – – – – – (102,188) – (102,188)
Dividend distribution – – – – – – – (41) (41)
Share based costs – – – 8,629 – – 8,629 – 8,629
Share based payments2                     – (21,740) – (6,131) – – (27,871) – (27,871)
Balance at December 31, 2024 141,173 875,952 (81,192) 18,092 (13,138) (1,572) 939,315 155 939,470
1 See Note 13
2 The third instalment of IPC RSP 2021 awards, the second instalment of IPC RSP 2022 awards, the first instalment of IPC RSP 2023 awards and 
the IPC PSP 2021 awards vested on February 1, 2024, at a price of CAD 14.90 per award. The difference between the value at vesting date and 
at grant (respectively CAD 4.07 per award, CAD 9.09 per award, CAD 14.27 per award and CAD 3.61 per award) was offset against retained 
earnings. 
See accompanying notes to the interim condensed consolidated financial statements

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

8
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED
1. CORPORATE INFORMATION AND MATERIAL ACCOUNTING POLICIES
A. The Group
International Petroleum Corporation (“IPC” or the “Corporation” and, together with its subsidiaries, the “Group”) is in the business 
of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development 
projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange (“TSX”) in Canada and the Nasdaq Stockholm 
Exchange in Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada under the Business Corporations 
Act. The address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business 
address is Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
B. Basis of preparation
The unaudited interim condensed consolidated financial statements have been prepared in accordance with IFRS Accounting 
Standards applicable to the preparation of interim financial statements, under International Accounting Standard 34, Interim 
Financial Reporting (together “IFRS Accounting Standards“). The unaudited interim condensed consolidated financial statements 
should be read in conjunction with IPC’s annual audited consolidated financial statements for the year ended December 31, 2024, 
which have been prepared in accordance with IFRS accounting 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 6, 2025.
The unaudited interim condensed consolidated financial statements have been prepared following the same accounting policies 
and methods of application as those in the Group’s audited annual consolidated financial statements for the year ended December 
31, 2024.
C. Change in presentation
Certain comparative figures have been reclassified to conform with the financial statements presentation in the current year.
D. Going concern
The Group’s unaudited interim condensed consolidated financial statements for the three months period ended March 31, 2025, 
have been prepared on a going concern basis, which assumes that the Group will be able to realize its assets and discharge its 
liabilities in the normal course of business as they become due in the foreseeable future.
E. Changes in accounting policies and disclosures
During the three months ended March 31, 2025, the Group applied the amended accounting standards, interpretations and annual 
improvement points that are effective as of January 1, 2025.

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

9
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED
2. SEGMENT INFORMATION
The Group operates within several geographical areas. Operating segments are reported at a country level which is consistent with 
the internal reporting provided to the CEO, who is the chief operating decision maker.
The following tables present segment information regarding: revenue, production costs, other operating costs and gross profit/
(loss). The Group derives its revenue from contracts with customers primarily through the transfer of oil and gas at a point in time. 
In addition, certain identifiable asset segment information is reported in Note 7 and 8.
Three months ended 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
Three months ended March 31, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 169,616 18,553 16,717 – 204,886
NGLs 244 – – – 244
Gas 14,417 – – – 14,417
Net sales of oil and gas 184,277 18,553 16,717 – 219,547
Change in under/over lift position – – 2,916 – 2,916
Royalties (24,483) – (1,139) – (25,622)
Hedging settlement 9,206 – – – 9,206
Other operating revenue – – 217 155 372
Revenue 169,000 18,553 18,711 155 206,419
Operating costs (59,889) (7,016) (8,911) – (75,816)
Cost of blending (45,206) – – – (45,206)
Change in inventory position 139 5,039 99 – 5,277
Depletion and decommissioning costs (22,904) (7,030) (3,219) – (33,153)
Depreciation of other tangible fixed assets – (2,262) – – (2,262)
Exploration and business development costs – – – (75) (75)
Gross profit 41,140 7,284 6,680 80 55,184

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

10
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED
3. PRODUCTION COSTS
Three months ended March 31
USD Thousands 2025 2024
Cost of operations 58,202 65,013 
Tariff and transportation expenses 9,944 9,543 
Direct production taxes 1,007 1,260 
Operating costs 69,153 75,816 
Cost of blending1 37,726 45,206 
Change in inventory position (3,500) (5,277)
Total production costs 103,379 115,745 
1  In Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. Cost of blending represents the contracted 
purchase of diluent used for blending.
4. FINANCE INCOME
Three months ended March 31
USD Thousands 2025 2024
Foreign exchange gain, net 18 –
Interest income 1,634 5,617 
Total finance income 1,652 5,617 
5. FINANCE COSTS
Three months ended March 31
USD Thousands 2025 2024
Foreign exchange loss, net – 2,061 
Interest expense 8,761 8,818
Unwinding of asset retirement obligation discount 3,957 3,618 
Amortization of capitalized financing fees 519 510
Loan commitment fees 230 222 
Currency hedge losses, net 6,858 –
Other financial costs 182 158 
Total finance costs 20,507 15,387

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

11
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED
6. INCOME TAX
Three months ended March 31
USD Thousands 2025 2024
Current tax (514) (1,373)
Deferred tax (4,165) (6,373)
Total tax expense (4,679) (7,746)
The Group is within the scope of the OECD Pillar Two model rules. The Group applies the exception to recognising and disclosing 
information about deferred tax assets and liabilities related to Pillar Two income taxes, as provided in the amendments to IAS 12 
issued in May 2023. 
Specification of deferred tax assets and tax liabilities1
USD Thousands March 31, 2025 December 31, 2024
Unused tax loss carry forward  42,298  40,042 
Derivative hedges  3,439  3,933 
Other  9,302  10,302
Deferred tax assets 55,039 54,277
Accelerated allowances  152,904  145,358
Derivative hedges 94 –
Deferred tax liabilities 152,998 145,358
Deferred taxes, net  (97,959)  (91,081)
1  The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the 
balance sheet when they relate to the same jurisdiction.
The deferred tax liabilities consist of accelerated allowances, being the difference between the book and the tax value of oil and 
gas properties and site restoration provisions. The deferred tax liabilities will be released over the life of the oil and gas assets as 
the book value is depleted for accounting purposes. 
Deferred tax assets in relation to tax loss carried forwards are only recognized in so far that there is a reasonable certainty as to
the timing and the extent of their realization. The recognized unused tax loss carry forward mainly relates to Canada. The Group
has concluded that the deferred assets will be recoverable using the estimated future taxable income based on the approved
business plans and budgets.

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

12
7. EXPLORATION AND EVALUATION ASSETS
USD Thousands Canada Malaysia France Total
Cost
January 1, 2025 480 – – 480
Additions 1,818 – – 1,818
Write-off – – – –
Currency translation adjustments (1) – – (1)
Net book value March 31, 2025 2,297 – – 2,297
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 – – – –
Additions 500 1,407 12 1,919
Write-off – (1,407) (12) (1,419)
Currency translation adjustments (20) – – (20)
Net book value December 31, 2024 480 – – 480
8. PROPERTY, PLANT AND EQUIPMENT
USD Thousands 2025 2024
Oil and gas properties                 1,558,146    1,484,487
Other tangible fixed assets  14,492    16,425
Property, Plant and Equipment  1,572,638    1,500,912
Oil and gas properties
USD Thousands Canada Malaysia France Total
Cost
January 1, 2025 1,767,580 599,734 405,129 2,772,443
Additions 93,377 592 3,099 97,068
Change in estimates (779) – – (779)
Currency translation adjustments 3,114 – 16,531 19,645
March 31, 2025 1,863,292 600,326 424,759 2,888,377
Accumulated depletion
January 1, 2025 (451,017) (530,315) (306,624) (1,287,956)
Depletion charge for the period (21,099) (5,751) (2,166) (29,016)
Currency translation adjustments (795) – (12,464) (13,259)
March 31, 2025 (472,911) (536,066) (321,254) (1,330,231)
Net book value March 31, 2025 1,390,381 64,260 103,505 1,558,146
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

13
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 1,465,010 591,123 436,693 2,492,826
Additions 412,284 17,035 3,475 432,794
Disposals (94) – – (94)
Change in estimates 36,995 (8,424) (9,018) 19,553
Reclassification (10,773) – – (10,773)
Currency translation adjustments (135,842) – (26,021) (161,863)
December 31, 2024 1,767,580 599,734 405,129 2,772,443
Accumulated depletion
January 1, 2024 (398,288) (502,834) (313,282) (1,214,404)
Depletion charge for the year (88,583) (27,481) (12,328) (128,392)
Disposals 94 – – 94
Currency translation adjustments 35,760 – 18,986 54,746
December 31, 2024 (451,017) (530,315) (306,624) (1,287,956)
Net book value December 31, 2024 1,316,563 69,419 98,505 1,484,487
Other tangible fixed assets
USD Thousands FPSO Other Total
Cost
January 1, 2025 204,853 9,824 214,677
Additions – 28 28
Disposal – (6) (6)
Currency translation adjustments – 201 201
March 31, 2025 204,853 10,047 214,900
Accumulated depreciation
January 1, 2025 (190,056) (8,196) (198,252)
Depreciation charge for the year (1,917) (78) (1,995)
Disposal – 6 6
Currency translation adjustments – (167) (167)
March 31, 2025 (191,973) (8,435) (200,408)
Net book value March 31, 2025 12,880 1,612 14,492
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

14
USD Thousands FPSO Other Total
Cost
January 1, 2024 204,853 10,048 214,901
Additions – 363 363
Currency translation adjustments – (587) (587)
December 31, 2024 204,853 9,824 214,677
Accumulated depreciation
January 1, 2024 (181,123) (8,340) (189,463)
Depreciation charge for the year (8,933) (334) (9,267)
Currency translation adjustments – 478 478
December 31, 2024 (190,056) (8,196) (198,252)
Net book value December 31, 2024 14,797 1,628 16,425
The Floating Production Storage and Offloading facility (“FPSO“) located on the Bertam field, Malaysia, is being depreciated to its 
residual value on a unit of production basis to August 2025. The depreciation charge is included in the depreciation of other assets 
line in the statement of operations.
For office equipment and other assets, the depreciation charge for the year is based on cost and an estimated useful life of 3 to 
5 years. The depreciation charge is included within the general, administration and depreciation expenses in the Statement of 
Operations.
9. OTHER NON-CURRENT ASSETS
USD Thousands March 31, 2025 December 31, 2024
Financial assets  34,822     34,788  
Intangible assets  13,869     13,877    
 48,691     48,665       
Financial assets mainly represent cash payments made in local currency to an asset retirement obligation fund for the Bertam 
field, Malaysia for an amount equivalent of USD 30.8 million (2024: USD 30.6 million). Financial assets also include cash-
collateralized guarantees placed in 2023 in respect of work commitments in Malaysia amounting to USD 4.0 million. 
Intangible assets mainly represent carbon offsets purchased in Canada. 
10. INVENTORIES
USD Thousands March 31, 2025 December 31, 2024
Hydrocarbon stocks 15,216  11,250    
Well supplies and operational spares 9,810  8,823    
25,026  20,073    
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

15
11. TRADE AND OTHER RECEIVABLES
USD Thousands March 31, 2025 December 31, 2024
Trade receivables  80,759    94,265    
Underlift  2,221    1,007       
Joint operations debtors  1,718    1,432    
Prepaid expenses and accrued income  11,237    12,346
Other  9,454    18,400 
 105,389    127,450    
Other receivables include secured amounts of USD 7.7 million towards the future asset retirement obligation for the Bertam 
field.
12. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include only cash at hand or held in bank accounts. 
13. SHARE CAPITAL
The Corporation’s issued common share capital is as follows:
Number of shares
Balance at January 1, 2024 126,992,066
Cancellation of repurchased common shares (NCIB) (7,822,595)
Balance at December 31, 2024 119,169,471
Cancellation of repurchased common shares (NCIB) (3,992,957)
Balance at March 31, 2025 115,176,514
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. The 
Corporation is authorized to issue an unlimited number of Common Shares without par value.
As at January 1, 2024, IPC had a total of 126,992,066 common shares issued and outstanding, with no common shares held in 
treasury.
During 2024, under the normal course issuer bid (NCIB) announced in December 2023 and renewed in December 2024, IPC 
purchased and cancelled an aggregate of 7,822,595 common shares.
As at December 31, 2024, IPC had a total of 119,169,471 common shares issued and outstanding, and held 110,156 common 
shares in treasury.
During Q1 2025, 3,670,983 common shares under the NCIB and 211,818 common shares under certain other exemptions in 
Canada. All of these purchased common shares, including the common shares held in treasury as at December 31, 2024, were 
cancelled during Q1 2025.
As at March 31, 2025, IPC had a total of 115,176,514 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, 2025 and 2024, UNAUDITED

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

16
14. EARNINGS PER SHARE
Basic earnings per share are based on net result attributable to the common shareholders and is calculated based upon the 
weighted-average number of common shares outstanding during the years presented.
Three months ended March 31
2025 2024
Net result attributable to shareholders of the Parent Company, USD 16,228,987 33,712,061
Weighted average number of shares for the period 119,124,606 126,974,800
Earnings per share, USD 0.14 0.27
Weighted average diluted number of shares for the period  120,309,604  128,276,966 
Earnings per share fully diluted, USD 0.13 0.26
15. FINANCIAL LIABILITIES
USD Thousands March 31, 2025 December 31, 2024
Current bank loans  3,549    3,402
Non current bank loans  900    1,719
Bonds  444,177    443,407
Capitalized financing fees (3,120)    (3,545) 
 445,506    444,983
As at March 31, 2025, IPC had USD 450 million of bonds outstanding, maturing in February 2027 with a fixed coupon rate of 
7.25% per annum, payable in semi-annual instalments in August and February.
Of the USD 450 million of bonds outstanding, USD 150 million of bonds were issued at 7% discount to par value with proceeds 
amounting to USD 139.5 million before transaction costs. For accounting purposes, the discounted amount was recognised in the 
balance sheet and the discount will be unwound over the period to maturity of the bond and charged to the interest expense line 
of the statement of operations using the effective interest rate methodology.
The bond repayment obligations as at March 31, 2025, are classified as non-current as there are no mandatory repayments within 
the next twelve months.
In addition, as at March 31, 2025, the Group had a revolving credit facility of CAD 180 million (the “Canadian RCF”) in connection 
with its oil and gas assets in Canada. The Canadian RCF has a maturity in May 2026 and is undrawn and fully available as at 
March 31, 2025. During Q3 2024, the Group entered into a letter of credit facility in Canada (the “LC Facility”) to cover existing 
operational letters of credit. As at March 31, 2025, operational letters of credit in an aggregate of CAD 40.2 million have 
been issued under the LC Facility, including letters of credit of CAD 35 million to support the third party pipeline construction 
agreements for the Blackrod project which are expected to be released as construction is completed during 2025.
As at March 31, 2025, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May
2026. IPC makes quarterly repayments of the France Facility and the amount remaining outstanding under the France Facility as 
at March 31, 2025 was USD 4.4 million (EUR 4.1 million). An amount of USD 3.5 million (EUR 3.3 million) drawn under the France 
Facility as at March 31, 2025 is classified as current representing the repayment planned within the next twelve months.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

17
16. PROVISIONS
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2025 267,790 1,679 3,685 2,072 275,226
Additions – – – 253 253
Unwinding of asset retirement obligation discount 3,957 – – – 3,957
Payments (321) – – (703) (1,024)
Change in estimates (779) – – – (779)
Currency translation adjustments 1,899 12 – 33 1,944
March 31, 2025 272,546 1,691 3,685 1,655 279,577
Non-current 266,731 565 3,685 1,655 272,636
Current 5,815 1,126 – – 6,941
Total 272,546 1,691 3,685 1,655 279,577
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2024 253,949 2,176 551 2,078 258,754
Additions – – 682 544 1,226
Disposals (197) – – – (197)
Unwinding of asset retirement obligation discount 14,568 – – – 14,568
Payments (7,711) (591) (906) (500) (9,708)
Change in estimates 19,553 – 3,491 – 23,044
Reclassification1 1,013 – – – 1,013
Currency translation adjustments (13,385) 94 (133) (50) (13,474)
December 31, 2024 267,790 1,679 3,685 2,072 275,226
Non-current 261,632 1,120 3,685 2,072 268,509
Current 6,158 559 – – 6,717
Total 267,790 1,679 3,685 2,072 275,226
1 The reclassification of the asset retirement obligation related to the 2024 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 9). 
The farm-in obligation relates to future payments for historic costs on the Bertam field in Malaysia payable for every 1 MMboe 
gross that the field produces above 10 MMboe gross and is capped at cumulative production of 27.5 MMboe gross. 
In calculating the present value of the asset retirement obligation provision, a blended rate of 6% (2024: 6%) per annum was used, 
based on a credit risk adjusted rate.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

18
17. TRADE AND OTHER PAYABLES
USD Thousands March 31, 2025 December 31, 2024
Trade payables  37,260     42,634    
Joint operations creditors 7,325  11,671    
Accrued expenses 117,641  119,316    
Other 2,857  2,750    
165,083  176,371    
18. FINANCIAL ASSETS AND LIABILITIES
Financial assets and liabilities by category
The accounting policies for financial instruments have been applied to the line items below:
March 31, 2025
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 34,822 34,822 – –
Derivative instruments 377 – – 377
Joint operation debtors 1,718 1,718 – –
Other current receivables2 95,060 92,839 2,221 –
Cash and cash equivalents 140,194 140,194 – –
Financial assets 272,171 269,573 2,221 377
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
March 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 441,957 441,957 – –
Current financial liabilities 3,549 3,549 – –
Derivative instruments 14,676 – – 14,676
Joint operation creditors 7,325 7,325 – –
Other current liabilities 158,160 158,160 – –
Financial liabilities 625,667 610,991 – 14,676
December 31, 2024
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 34,788 34,788 – –
Derivative instruments 3,219 – – 3,219
Joint operation debtors 1,432 1,432 – –
Other current receivables2 115,186 114,179 1,007 –
Cash and cash equivalents 246,593 246,593 – –
Financial assets 401,218 396,992 1,007 3,219
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

19
December 31, 2024
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 441,581 441,581 – –
Current financial liabilities 3,402 3,402 – –
Derivative instruments 20,431 – – 20,431
Joint operation creditors 11,671 11,671 – –
Other current liabilities 165,846 165,846 – –
Financial liabilities 642,931 622,500 – 20,431
The carrying amount of the Group’s financial assets and liabilities approximate their fair values at the balance sheet dates.
 For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
  – Level 1: based on quoted prices in active markets;
  – Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
  – Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
March 31, 2025
USD Thousands Level 1 Level 2 Level 3
Other current receivables 2,221 – –
Derivative instruments – current – 377 –
Derivative instruments – non-current – – –
Financial assets 2,221 377 –
Derivative instruments – current – 13,146 –
Derivative instruments – non-current – – 1,530
Financial liabilities – 13,146 1,530
December 31, 2024
USD Thousands Level 1 Level 2 Level 3
Other current receivables 1,007 – –
Derivative instruments – current – 3,219 –
Derivative instruments – non-current – – –
Financial assets 1,007 3,219 –
Derivative instruments – current – 19,869 –
Derivative instruments – non-current – – 562
Financial liabilities – 19,869 562
The Group had oil price sale financial hedges outstanding as at March 31, 2025 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
April 1, 2025 - December 31, 2025 11,700 WTI/WCS Differential USD -14.26/bbl
April 1, 2025 - December 31, 2025 10,000 WTI Sale Swap USD 71.30/bbl
April 1, 2025 - December 31, 2025 2,000 Brent Sale Swap USD 75.78/bbl
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

20
The Group had gas price sale financial hedges outstanding as at March 31, 2025 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
April 1, 2025 - October 31, 2025 20,000 AECO Gas Swap CAD 2.25/GJ
April 1, 2025 - December 31, 2025 10,000 AECO Gas Swap CAD 2.50/GJ
The Group had electricity financial hedges outstanding as at March 31, 2025 which are summarized as follows:
Period Volume (MW) Type Average Pricing 
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
The Group entered into currency hedges to purchase :
(i) a total CAD 357.5 million for the period April 2025 to December 2025 at an average rate of CAD 1.36 (sell USD);
(ii) a total EUR 20.25 million for the period April 2025 to December 2025 at an average rate of EUR 1.07 (sell USD);
(iii) a total MYR 102 million for the period April 2025 to December 2025 at an average rate of MYR 4.39 (sell USD).
All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
19. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In the normal course of business, the Group has committed to certain payments which are not recognised as liabilities. The 
following table summarizes the Group’s commitments in Canada as at March 31, 2025:
CAD Millions 2025 2026 2027 2028 2029 Thereafter
Transportation service1 24.6 59.3 88.2 92.8 96.6 1,395.7
Power2 10.9 12.4 12.4 9.8 – –
Total commitments 35.5 71.7 100.6 102.6 96.6 1,395.7
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2045.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from April 1, 2025 to December 31, 
2028, an additional 5MWh at a weighted average price of CAD 58.31/MWh from April 1, 2025 to December 31, 2027, and an additional 5MWh at a 
weighted average price of CAD 46.85/MWh from April 1, 2025 to December 31, 2025.
20. RELATED PARTIES
The Group recognises the following related parties: associated companies, jointly controlled entities, key management personnel and 
members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or of its 
family or of any individual that controls, or has joint control or significant influence over the entity.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with 
parties at arm’s length.
During the first quarter of 2025, the Group has not entered into material transactions with related parties.
21. SUBSEQUENT EVENTS
No events have occurred since March 31, 2025, that are expected to have a substantial effect on this report.                         
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2025 and 2024, UNAUDITED

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

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

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

Q1
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three months ended March 31, 2025

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Contents
Non-IFRS Measures
References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA), 
“operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under IFRS Accounting Standards (IFRS) and do not have any 
standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF , FCF , EBITDA, operating costs and net debt/net cash that may 
be used by other public companies. Management believes that OCF , FCF , EBITDA, operating costs and net debt/net cash are useful supplemental measures that may 
assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Non-IFRS measures should not be 
considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS measure is presented in this 
MD&A. See “Non-IFRS Measures” on page 16.
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 22.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada are effective as of December 
31, 2024, and are included in the reports prepared by Sproule Associates Limited (Sproule), an independent qualified reserves evaluator, in accordance with National 
Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using 
Sproule’s December 31, 2024, price forecasts. 
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in France and Malaysia are effective as of 
December 31, 2024, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), an independent qualified reserves auditor, in accordance with NI 51-101 and 
the COGE Handbook, and using Sproule’s December 31, 2024, price forecasts. 
Certain abbreviations and technical terms used in this MD&A are defined or described under the heading “Other Supplementary Information”.
INTRODUCTION  3
HIGHLIGHTS  4
OPERATIONS REVIEW  5
• Business Overview 5
• Operations Overview  7
FINANCIAL REVIEW  10
• Financial Results 10
• Capital Expenditure 15
• Financial Position and Liquidity  15
• Non-IFRS Measures 16
• Off-Balance Sheet Arrangements  18
• Outstanding Share Data  18
• Contractual Obligations and Commitments  19
• Material Accounting Policies and Estimates 19
• Transactions with Related Parties  20
• Financial Risk Management  20
RISK FACTORS 21
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING  21
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION  22
RESERVES AND RESOURCES ADVISORY  24
OTHER SUPPLEMENTARY INFORMATION 26
2

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
INTRODUCTION
This management’s discussion and analysis (“MD&A”) for International Petroleum Corporation (“IPC” or the “Corporation” 
and, together with its subsidiaries, the “Group”) is dated May 6, 2025 and is intended to provide an overview of the Group’s 
operations, financial performance and current and future business opportunities. This MD&A should be read in conjunction with 
IPC’s unaudited interim condensed consolidated financial statement for the period ended March 31, 2025 as well as the audited 
consolidated financial statements and accompanying notes for the year ended December 31, 2024 (“Financial Statements”).
Group Overview
The Group is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production 
assets and development projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in 
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada, under the Business Corporations Act. The 
address of its registered office is Suite 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is 
Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
Basis of Preparation
The MD&A and the Financial Statements have been prepared in accordance with IFRS Accounting Standards (“IFRS”) as issued by
the International Accounting Standards Board (“IASB”). 
Financial information is presented in United States Dollars (“USD”). However, as the Group operates in Europe and in Canada, 
certain financial information prepared by subsidiaries has been reported in Euros (“EUR”) and in Canadian Dollars (“CAD”). In 
addition, certain costs relating to the operations in Malaysia, which are reported in USD, are incurred in Malaysian Ringgit (“MYR”). 
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
March 31, 2025 March 31, 2024 December 31, 2024
Average Period end Average Period end Average Year end
1 EUR equals USD 1.0807 1.0815 1.0857 1.0811 1.0821 1.0389
1 USD equals CAD 1.4352 1.4362 1.3484 1.3571 1.3698 1.4388
1 USD equals MYR 4.4475 4.4375 4.7234 4.7330 4.5759 4.4715
              
3

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
HIGHLIGHTS
Q1 2025 Business Highlights
• Average net production of approximately 44,400 boepd for the first quarter of 2025, within the guidance range for the period 
(52% heavy crude oil, 15% light and medium crude oil and 33% natural gas).(1)
• Continued progressing Phase 1 development activity as well as future phase resource maturation works at the Blackrod 
asset. 
• At Onion Lake Thermal, all four planned production infill wells and the final Pad L well pair have been successfully drilled.
• 3.9 million IPC common shares purchased and cancelled during Q1 2025 and continuing with target to complete the full 
2024/2025 NCIB this year.
Q1 2025 Financial Highlights
• Operating costs per boe of USD 17.3 for Q1 2025, in line with guidance.(3)
• Operating cash flow (OCF) generation of MUSD 75 for Q1 2025, in line with guidance .(3)
• Capital and decommissioning expenditures of MUSD 99 for Q1 2025, in line with guidance.
• Free cash flow (FCF) generation for Q1 2025 amounted to MUSD -43 (MUSD 37 pre-Blackrod capital expenditure) .(3)
• Gross cash of MUSD 140 and net debt of MUSD 314 as at March 31, 2025.(3)
• Net result of MUSD 16 for Q1 2025.
Reserves and Resources
• Total 2P reserves as at December 31, 2024 of 493 MMboe, with a reserve life index (RLI) of 31 years. (1)(2)
• Contingent resources (best estimate, unrisked) as at December 31, 2024 of 1,107 MMboe.(1)(2)
• 2P reserves net asset value (NAV) as at December 31, 2024 of MUSD 3,083 (10% discount rate). (1)(2)
2025 Annual Guidance
• Full year 2025 average net production guidance range forecast maintained at 43,000 to 45,000 boepd. (1)
• Full year 2025 operating costs guidance range forecast maintained at USD 18 to 19 per boe. (3)
• Full year 2025 OCF revised guidance estimated at between MUSD 240 and 270 (assuming Brent USD 60 to 75 per barrel for 
the remainder of 2025) from previous guidance of between MUSD 210 and 280 (assuming Brent USD 65 to 85 per barrel). (3)(4)
• Full year 2025 capital and decommissioning expenditures guidance forecast maintained at MUSD 320 .
• Full year 2025 FCF revised guidance estimated at between MUSD -135 and -110 (assuming Brent USD 60 to 75 per barrel for 
the remainder of 2025) from previous guidance of between MUSD -150 and -80 (assuming Brent USD 65 to 85 per barrel), 
after taking into account MUSD 230 of forecast full year 2025 capital expenditures relating to the Blackrod asset .(3)(4)
Three months ended March 31
USD Thousands 2025 2024
Revenue 178,492 206,419
Gross profit 44,149 55,184
Net result 16,231 33,719
Operating cash flow(3) 74,790 89,301
Free cash flow(3) (43,172) (43,311)
EBITDA(3) 70,946 87,020
Net cash/(debt)(3) (314,255) (60,572)
4

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
OPERATIONS REVIEW 
Business Overview
During the first quarter of 2025, oil prices were relatively stable, with Brent prices averaging just below USD 76 per barrel. 
Following the quarter, commodity prices pulled back with spot Brent rates falling to USD 60 per barrel in April 2025. The physical 
crude market remained tight throughout the first quarter, prompting OPEC and the OPEC+ group to increase supply ahead of 
expectations. The timing of the supply increases coincided with the United States proposing harsh tariffs to countries deemed 
in a trade surplus of US goods. These two events have impacted future crude supply and demand outlooks, in turn weighing on 
spot and future oil benchmark prices. Despite the poor market sentiment, global inventories remain below the 5-year average, 
high geopolitical tensions persist, non-OPEC 2025 oil production (namely, in the US) is unlikely to grow at current prices, and US 
Federal Reserve Bank rate cuts are likely to occur in the near future. IPC prudently supplemented downside protection measures 
at the beginning of the first quarter of 2025 through financial swap hedging arrangements which in total represent nearly 40% 
of our forecast 2025 oil production at around USD 76 and USD 71 per barrel for Dated Brent and West Texas Intermediate (WTI), 
respectively, for the remainder of 2025.  
 
In Canada, WTI to Western Canadian Select (WCS) crude price differentials during the first quarter of 2025 averaged just under 
USD 13 per barrel, with spot differentials decreasing to around USD 9 per barrel in April 2025. The Western Canadian Sedimentary 
Basin (WCSB) petroleum producers have greatly benefited from the TMX pipeline expansion with differentials tightening to levels 
not seen since 2020. There are currently no tariffs on Canadian crude exports to the United States, which remain covered by the 
US Mexico Canada free trade agreement. IPC has hedged the WTI/WCS differential for approximately 50% of our forecast 2025 
Canadian oil production at USD 14 per barrel for 2025.
Natural gas markets in Canada for the first quarter of 2025 remained weak, given the softer than average winter weather 
conditions and high natural gas storage levels. The average AECO gas price was CAD 2.1 per Mcf for the first quarter of 2025. The 
forward strip implies improved pricing for Canadian gas benchmark prices, driven by the pending startup of the West Coast LNG 
Canada project later this year. Approximately 50% of our net long exposure is hedged at CAD 2.4 per Mcf to end October 2025, 
dropping to around 15% for November and December at CAD 2.6 per mcf.
First Quarter 2025 Highlights and Full Year 2025 Guidance 
During the first quarter of 2025, our portfolio delivered average net production of 44,400 boepd, in line with guidance. Operational 
performance from our producing assets was strong to start the year as high facility and well uptimes were achieved. Drilling 
activity commenced in the first quarter of 2025 at Onion Lake Thermal, which aims to sustain production levels at the asset for 
2025. In Malaysia, drilling and well maintenance works are planned to start in the second quarter of 2025, in line with plan. We 
maintain the full year 2025 average net production guidance range of 43,000 to 45,000 boepd.(1)
Our operating costs per boe for the first quarter of 2025 was USD 17.3, in line with guidance. Full year 2025 operating expenditure 
guidance of USD 18.0 to 19.0 per boe remains unchanged.(3)
Operating cash flow (OCF) generation for the first quarter of 2025 was MUSD 75. Full year 2025 OCF guidance is tightened to 
MUSD 240 to 270 (assuming Brent USD 60 to 75 per barrel for the remainder of 2025).(3)(4)
Capital and decommissioning expenditure for the first quarter of 2025 was MUSD 99 in line with guidance. Full year 2025 capital 
and decommissioning expenditure of MUSD 320 is maintained.
Free cash flow (FCF) generation was MUSD -43 (MUSD 37 pre-Blackrod capital expenditure) during the first quarter of 2025. Full 
year 2025 FCF guidance is tightened to MUSD -135 to -110 (assuming Brent USD 60 to 75 per barrel for the remainder of 2025) 
after taking into account MUSD 320 of forecast full year 2025 capital expenditures (including MUSD 230 relating to the Blackrod 
asset).(3)(4)
As at March 31, 2025, IPC’s net debt position was MUSD 314, from a net debt position of MUSD 209 as at December 31, 2024, 
mainly driven by the funding of forecast capital expenditures and the continuing share repurchase program (NCIB). Gross cash 
on the balance sheet as at March 31, 2025 amounts to MUSD 140 and IPC has access to an undrawn Canadian credit facility 
of greater than 130 MUSD. The access to liquidity supports IPC to follow through on its key strategic objectives of enhancing 
stakeholder value through organic growth, stakeholder returns, and pursuing value adding M&A.(3)
Blackrod
During the first quarter of 2025, IPC continued to advance the Phase 1 development of the Blackrod asset. Growth capital 
expenditure to first oil is maintained at MUSD 850. First oil of the Phase 1 development is estimated to be in late 2026, with 
forecast net production of 30,000 boepd by 2028. IPC forecasts capital expenditure in 2025 at the Blackrod asset of MUSD 230, 
of which MUSD 77 was invested in the Phase 1 development project during Q1 2025. Since the transformational organic growth 
project was sanctioned in early 2023, MUSD 669, or approximately 80% of the total multi-year project capital budget has been 
incurred.(1)
5

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Project activities for the multi-year Blackrod Phase 1 development have progressed according to plan. Engineering, procurement 
and fabrication is substantially complete with greater than 90% of all facility modules delivered to site. Equipment installation, 
piping inter-connects, electrical and instrumentation are the key areas of focus for construction at the Central Processing Facility 
(CPF) and well pad facilities.
Resource maturation drilling for future phase expansion considerations took place during Q1 2025. Commercial operational 
readiness planning has ramped up in line with our progressive turnover strategy to ensure a seamless transition from build to start-
up. IPC intends to fund the remaining Blackrod capital expenditure with forecast cash flow generated by its operations, cash on 
hand and drawing under the existing Canadian credit facility if needed.(3)
Stakeholder Returns: Normal Course Issuer Bid
In Q4 2024, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 7.5 million common 
shares over the period of December 5, 2024 to December 4, 2025. Under the 2024/2025 NCIB, IPC repurchased and cancelled 
approximately 0.8 million common shares in December 2024, 3.7 million common shares during Q1 2025, and a further 0.2 
million common shares purchased under other exemptions in Canada. The average price of common shares purchased under the 
2024/2025 NCIB during Q1 2025 was SEK 146 / CAD 20 per share.
As at March 31, 2025, IPC had a total of 115,176,514 common shares issued and outstanding and IPC held no common shares in 
treasury. As at April 30, 2025, IPC had a total of 114,248,119 common shares issued and outstanding and IPC held no common 
shares in treasury.
Notwithstanding the final major capital investment year at Blackrod in 2025, IPC had purchased and cancelled 73% of the 
maximum 7.5 million common shares allowed under the 2024/2025 NCIB by the end of April 2025 and intends to purchase and 
cancel the remaining 2.0 million common shares under that program in 2025. This would result in the cancellation of 6.2% of 
common shares outstanding as at the beginning of December 2024. IPC continues to believe that reducing the number of shares 
outstanding in combination with investing in long-life production growth at the Blackrod project will prove to be a winning formula 
for our stakeholders.
Environmental, Social and Governance (ESG) Performance
During the first quarter of 2025, IPC recorded no material safety or environmental incidents.
As previously announced, IPC targets a reduction of our net GHG emissions intensity by the end of 2025 to 50% of IPC’s 2019 
baseline and IPC remains on track to achieve this reduction. IPC has also made a commitment to maintain 2025 levels of 20 kg 
CO2/boe through to the end of 2028.(5)
Notes:
(1) See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory” below. See also the 
annual information form for the year ended December 31, 2024 (AIF) available on IPC’s website at www.international-
petroleum.com and under IPC’s profile on SEDAR+ at www.sedarplus.ca. 
 
(2) See “Reserves and Resources Advisory“ below. Further information with respect to IPC’s reserves, contingent resources 
and estimates of future net revenue, including assumptions relating to the calculation of net present value (NPV), are 
described in the AIF . NAV is calculated as NPV less net debt of USD 209 million as at December 31, 2024.
(3) Non-IFRS measures, see “Non-IFRS Measures” below.
(4) OCF and FCF forecasts at Brent USD 60 and 70 per barrel assume Brent to WTI differential of USD 3 and 5 per barrel, 
respectively, and WTI to WCS differential of USD 10 and 15 per barrel, respectively, for the remainder of 2025. OCF and 
FCF forecasts assume gas price on average of CAD 2.25 per Mcf for the remainder of 2025. 
(5) Emissions intensity is the ratio between oil and gas production and the associated carbon emissions, and net emissions 
intensity reflects gross emissions less operational emission reductions and carbon offsets.
6

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Operations Overview 
Q1 2025 Overview
In Q1 2025, IPC continued to successfully demonstrate its commitment to operational excellence, delivering annual net average 
daily production in line with our Capital Markets Day (CMD) guidance with no material safety or environmental incidents recorded 
in the quarter.
Budgeted capital expenditure activity started in Q1 2025 and is progressing in line with expectations. 
In Canada, the Blackrod Phase 1 development continues to progress in line with schedule and budget. Engineering, procurement 
and fabrication is substantially complete with greater than 90% of all facility modules delivered to site. Equipment installation, 
piping inter-connects, electrical and instrumentation are the key areas of focus for construction in the Central Processing Facility 
(CPF) and well pad facilities. Third-party transport pipeline installation is progressing on schedule while production well pad drilling 
is ahead of schedule. At Onion Lake Thermal, all four planned production infill wells and the final Pad L well pair have been 
successfully drilled with completion activity ongoing. The new wells will be brought online through the year, with a phased well 
heat conformance and production start-up plan initiated.
In Malaysia, preparations for the planned infill well drilling and well maintenance activity have continued and remain on track to 
commence in Q2 2025. 
In France, field development studies continue with the next phase of production well targets matured and ready for sanction at the 
Corporation’s discretion.
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 493 MMboe as at December 31, 2024, as certified by independent 
third party reserve auditors. The proved plus probable reserve life index (RLI) as at December 31, 2024, is approximately 31 years. 
Best estimate contingent resources as at December 31, 2024, are 1,107 MMboe (unrisked). See “Reserves and Resources 
Advisory” below.
Production
Average daily net production for Q1 2025 was in line with our CMD guidance at 44,400 boepd. In Canada, strong operational 
performance at the major oil and gas assets has been supplemented by a continued positive production response at the Mooney 
Phase 2 enhanced oil recovery (EOR) polymer flood. At the Bertam field in Malaysia, average daily production remained strong in 
Q1 2025, with high production uptime and a continued focus on well rate optimization activity to offset natural declines. In France, 
stable production performance continues at all the major producing assets. 
With strong operational delivery during the first quarter 2025, and a strong production outlook for the remainder of the
year, IPC remains well positioned to deliver an annual net average daily production within the guidance range of 43,000 to 45,000 
boepd. 
The production during Q1 2025 with comparatives is summarized below:
Production
in Mboepd
Three months ended
March 31
Year ended
December 31
2025 2024 2024
Crude oil
Canada – Northern Assets 13.9 15.0 14.2
Canada – Southern Assets 10.8 11.2 11.1
Malaysia 2.9 4.1 3.8
France 2.1 2.5 2.4
Total crude oil production 29.7 32.8 31.5
Gas
Canada – Northern Assets 0.5 0.3 0.5
Canada – Southern Assets 14.2 15.7 15.4
Total gas production 14.7 16.0 15.9
Total production 44.4 48.8 47.4
Quantity in MMboe 4.00 4.44 17.34
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, 2025
CANADA
Production
in Mboepd
Working Interest
(WI)
Three months ended
March 31
Year ended
December 31
2025 2024 2024
- Oil Onion Lake Thermal 100% 11.5 13.3 12.3
- Oil Suffield Area 100% 9.3 10.0 9.7
- Oil Other 50-100% 3.9 2.9 3.3
- Gas ~100% 14.7 16.0 15.9
Canada 39.4 42.2 41.2
 
Production
Net production from IPC’s assets in Canada during Q1 2025 was in line with guidance at 39,400 boepd with continued strong 
operational performance at the major oil and gas producing assets. At Mooney, the Phase 2 EOR polymer flood project is 
performing ahead of expectations. Stable performance continued at Onion Lake Thermal during the planned drilling campaign.
Organic Growth and Capital Projects
In Canada, with the forecast final major spend year at the Blackrod Phase 1 project development, IPC announced a balanced 
non-Blackrod capital expenditure budget for 2025. IPC retains the ability to increase capital expenditure levels in Canada as we 
continue to mature opportunities across all the major assets. 
The Blackrod Phase 1 development project is progressing in line with schedule and budget. As at the end of Q1 2025, process 
facility fabrication is substantially complete supporting critical equipment site installation which continues to progress in line with 
plan. Third-party transport pipeline installation is progressing on schedule while production well pad drilling remains ahead of 
schedule.
Future phase resource maturation work at the Blackrod asset continued in Q1 2025, with all five planned appraisal wells drilled and 
results in line with expectations.
At Onion Lake Thermal, all four planned production infill wells and the final Pad L well pair have been successfully drilled with 
completion activity ongoing. The new wells will be brought online through the year, with a phased well steam conformance 
optimization and production startup plan initiated. A total of seven out of nine Pad L production wells are currently online with the 
eighth well expected online in Q2 2025.
During Q1 2025 at Ferguson, the two final 2024 drilled oil production wells have been brought online and are delivering in line with 
expectations. 
MALAYSIA
Production
in Mboepd WI
Three months ended
March 31
Year ended
December 31
2025 2024 2024
Bertam 100% 2.9 4.1 3.8
Production
Net production at Bertam in Malaysia in Q1 2025 was in line with guidance at 2,900 boepd with one production well offline 
awaiting workover intervention.
Organic Growth and Capital Projects
In Malaysia, preparations for the planned infill well drilling and well maintenance activity continued in Q1 2025 and remain on track 
to commence in Q2 2025.
8

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
FRANCE
Production
in Mboepd WI
Three months ended
December 31
Year ended
December 31
2025 2024 2024
France
- Paris Basin 100%1 1.9 2.1 2.1
- Aquitaine 50% 0.2 0.4 0.3
2.1 2.5 2.4
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q1 2025 was in line with guidance at 2,100 boepd with stable performance at all the major 
producing assets.   
Organic Growth
In France, field development studies continued in Q1 2025 with the next phase of production well targets matured and ready for 
sanction decision at the company’s discretion.
9

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
FINANCIAL REVIEW 
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q1-25 Q4-24 Q3-24 Q2-24 Q1-24 Q4-23 Q3-23 Q2-23
Revenue 178,492 199,124 173,200 219,040 206,419 198,460 257,366 205,564
Gross profit 44,149 42,774 39,505 72,708 55,184 39,955 93,429 52,747
Net result 16,231 415 22,875 45,210 33,719 29,710 71,681 32,025
Earnings per share – USD 0.14 0.00 0.19 0.36 0.27 0.23 0.56 0.24
Earnings per share fully
diluted – USD 0.13 0.00 0.18 0.36 0.26 0.22 0.54 0.24
Operating cash flow1 74,790 78,158 72,589 101,941 89,301 73,634 119,142 84,372
Free cash flow1 (43,172) (61,476) (38,269) 7,559 (43,311) (64,688) 34,703 16,415
EBITDA1 70,946 76,184 68,313 103,971 87,020 66,284 123,054 85,201
Net cash/(debt) at period end1 (314,255) (208,528) (157,228) (88,220) (60,572) 58,043 83,097 63,548
1 See definition on page 16 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands March 31, 2025 December 31, 2024
Non-current assets 1,627,403 1,554,833
Current assets 273,612 398,849
Total assets 1,901,015 1,953,682
Total non-current liabilities 817,350 806,134
Current liabilities 189,882 208,078
Total liabilities 1,007,332 1,014,212
Net assets 893,783 939,470
Working capital (including cash) 83,730 190,771
10

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Selected Interim Financial Information
The Group operates within several geographical areas. Operating segments are reported at a country level, with Canada being 
further analyzed by main areas: (i) Canada – Northern Assets (comprising mainly of the Onion Lake Thermal asset) and (ii) Canada –
Southern Assets (comprising mainly of the Suffield assets, including the Brooks assets). This is consistent with the internal 
reporting provided to the CEO, who is the chief operating decision maker. The following tables present certain segment 
information.
Three months ended – 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 (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 24,876 13,953 2,466 2,885 (31) 44,149
Three months ended – March 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 104,145 65,471 18,553 16,717 – 204,886
NGLs – 244 – – – 244
Gas 125 14,292 – – – 14,417
Net sales of oil and gas 104,270 80,007 18,553 16,717 – 219,547
Change in under/over lift position – – – 2,916 – 2,916
Royalties (15,495) (8,988) – (1,139) – (25,622)
Hedging settlement 5,255 3,951 – – – 9,206
Other operating revenue – – – 217 155 372
Revenue 94,030 74,970 18,553 18,711 155 206,419
Operating costs (20,658) (39,231) (7,016) (8,911) – (75,816)
Cost of blending (38,294) (6,912) – – – (45,206)
Change in inventory position 368 (229) 5,039 99 – 5,277
Depletion (9,744) (13,160) (7,030) (3,219) – (33,153)
Depreciation of other assets – – (2,262) – – (2,262)
Exploration and business
development costs – – – – (75) (75)
Gross profit 25,702 15,438 7,284 6,680 80 55,184
11

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Three months ended March 31, 2025, Review 
Revenue
Total revenue amounted to USD 178,492 thousand for Q1 2025, compared to USD 206,419 thousand for Q1 2024 and is analyzed 
as follows: 
USD Thousands 
Three months ended March 31
2025 2024
Crude oil sales 190,212 204,886
Gas and NGL sales 11,813 14,661
Change in under/overlift position 1,141 2,916
Royalties (23,628) (25,622)
Hedging settlement (1,216) 9,206
Other operating revenue 170 372
Total revenue 178,492 206,419
The main components of total revenue for Q1 2025 and Q1 2024 respectively, are detailed below. 
Crude oil sales
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
Three months ended – March 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 104,145 65,471 18,553 16,717 204,886
- Quantity sold in bbls 1,826,774 1,127,014 202,519 201,604 3,357,911
- Average price realized USD per bbl 57.01 58.09 91.61 82.92 61.02
Crude oil revenue was 7% lower in Q1 2025 compared to Q1 2024 with lower sales volumes. Prices were slightly higher in 
Canada, and lower in Malaysia and France in Q1 2025 compared to Q1 2024.
The Suffield area assets and Onion Lake Thermal crude oil in Canada is blended with purchased condensate diluent volumes 
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for 
Canada.
The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q1 2025, WTI averaged USD 71 per bbl compared to USD 77 per bbl for Q1 2024 and the 
average discount to WCS used in IPC’s pricing formula was USD 13 per bbl compared to USD 19 per bbl for Q1 2024.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia 
during Q1 2025 and one cargo lifting in Q1 2024. Produced unsold oil barrels from Bertam at the end of Q1 2025 amounted to 
146,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 76 per bbl for 
Q1 2025 compared to USD 83 per bbl for the comparative period.
12

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Gas and NGL sales
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
Three months ended – March 31, 2024
Canada –
 Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 125 14,536 14,661
- Quantity sold in Mcf 70,491 7,668,608 7,739,099
- Average price realized USD per Mcf 1.77 1.90 1.89
Gas and NGL sales revenue was 19% lower for Q1 2025 compared to Q1 2024 mainly due to the lower achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For the year Q1 2025, IPC realized an average price of CAD 
2.44 per Mcf compared to AECO average pricing of CAD 2.13 per Mcf.
Hedging settlement
IPC enters into risk management contracts in order to ensure a certain level of cash flow. It focuses mainly on oil and gas price 
swaps to limit pricing exposure. Oil and gas hedging contracts are not entered into for speculative purposes.
The realized hedging settlement for Q1 2025 amounted to a loss of USD 1,216 thousand and consisted of a loss of USD 1,500 
thousand on the oil contracts and a gain of USD 284 thousand on the gas contracts. Also see the Financial Position and Liquidity 
and the Financial Risk Management sections below.
Production costs
Production costs including inventory movements amounted to USD 103,379 thousand for Q1 2025 compared to USD 115,745 
thousand for Q1 2024 and is analyzed as follows:
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
13

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Three months ended – March 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 20,658 39,231 11,066 8,911 (4,050) 75,816
USD/boe2 14.89 16.05 29.36 38.89 n/a 17.09
Cost of blending 38,294 6,912 – – – 45,206
Change in inventory position (368) 229 (5,039) (99) – (5,277)
Production costs 58,584 46,372 6,027 8,812 (4,050) 115,745
1  See definition on page 16 under “Non-IFRS measures”.
2  USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and for 2024.
3Included in the Malaysia operating costs is the lease cost for the FPSO Bertam which is owned by the Group. Other represents the FPSO Bertam
lease fee self-to-self payment elimination. Netting the self-to-self elimination against the operating costs in Malaysia reduces the operating costs
per boe for Malaysia to USD 33.30 for Q1 2025 and USD 18.61 for the comparative period.
Operating costs
Operating costs amounted to USD 69,153 thousand for Q1 2025 compared to USD 75,816 thousand for Q1 2024. Operating costs 
per boe amounted to USD 17.30 per boe in Q1 2025 below the guidance and compared with USD 17.09 per boe in Q1 2024. 
Operating costs per boe in Malaysia increased in Q1 2025 compared to Q1 2024 due to lower production with one production well 
offline awaiting workover intervention planned in Q2 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 37,726 thousand for Q1 2025 compared to USD 45,206 thousand for Q1 2024. 
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 2025, IPC had crude entitlement of 146,000 bbl 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 29,016 thousand for Q1 2025 compared to USD 33,153 thousand 
for Q1 2024.
The depletion charge is analyzed in the following tables:
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
Three months ended – March 31, 2024
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,744 13,160 7,030 3,219 33,153
USD per boe2 7.02 5.38 18.65 14.05 7.47
1  In Canada, excludes the adjustment for accelerated decommissioning activities.
2  USD/boe in the tables above is calculated by dividing the depletion cost by the production volume for each country for the period.
The depletion charge is derived by applying the depletion rate per boe to the volumes produced in the period by each field. The 
depletion rate in Malaysia has significantly increased compared to the prior period due to lower production with one production 
well offline awaiting workover intervention planned in Q2 2025. 
14

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 1,917 thousand for Q1 2025 compared to USD 2,262 thousand for Q1 
2024. This relates to the depreciation of the FPSO Bertam, which is being depreciated to its residual value on a unit of production 
basis to August 2025.
Exploration and business development costs
The total exploration and business developments costs amounted to a cost of USD 31 thousand for Q1 2025.
Net financial items
Net financial items amounted to a charge of USD 18,855 thousand for Q1 2025, compared to a charge of USD 9,770 thousand for 
Q1 2024, and included a realized currency hedge loss and a net foreign exchange gain of respectively USD 6,858 thousand and 
USD 18 thousand for Q1 2025 compared to no realized currency hedges and a net foreign exchange loss of USD 2,061 thousand 
for Q1 2024. 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 12,015 thousand for Q1 2025, compared to USD 7,709 thousand for Q1 2024.
The interest expense amounted to USD 8,761 thousand for Q1 2025, compared to USD 8,818 thousand for the comparative period 
in 2024 and mainly related to the bond interest at a coupon rate of 7.25% per annum. Interest income generated on cash balances 
held amounted to USD 1,634 thousand for Q1 2025 and USD 5,617 thousand for Q1 2024.
The unwinding of the asset retirement obligation discount rate amounted to USD 3,957 thousand for Q1 2025 compared to USD 
3,618 thousand for Q1 2024. 
Income tax
The corporate income tax amounted to a charge of USD 4,679 thousand for Q1 2025, compared to a charge of USD 7,746 
thousand for Q1 2024.
The current income tax amounted to 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 2025 due to the usage of historical tax pools. 
Capital Expenditure
Development and exploration and evaluation expenditure incurred for the first three months of 2025 was as follows:
USD Thousands Canada –
 Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 90,342 3,035 592 3,099 97,068
Exploration and evaluation 1,818 – – – 1,818
92,160 3,035 592 3,099 98,886
Capital expenditure of USD 98,886 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project and on 
infill well drilling at Onion Lake Thermal.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 14,492 thousand as at March 31, 2025, which included USD 12,880 thousand in 
respect of the FPSO Bertam. The FPSO Bertam is being depreciated to its residual value on a unit of production basis to August 
2025.
Financial Position and Liquidity
Financing 
As at March 31, 2025, IPC had MUSD 450 of bonds outstanding, maturing in February 2027 with a fixed coupon rate of 7.25% per 
annum, payable in semi-annual instalments in August and February. The bond repayment obligations as at March 31, 2025, are 
classified as non-current as there are no mandatory repayments within the next twelve months.
In addition, as at March 31, 2025, the Group had a revolving credit facility of MCAD 180 (the “Canadian RCF”) in connection with 
its oil and gas assets in Canada. The Canadian RCF has a maturity in May 2026 and is undrawn and fully available as at March 31, 
2025. During Q3 2024, the Group entered into a letter of credit facility in Canada (the “LC Facility”) to cover existing operational 
letters of credit. As at March 31, 2025, operational letters of credit in an aggregate of MCAD 40.2 have been issued under the LC 
Facility, including letters of credit of MCAD 35 to support the third party pipeline construction agreements for the Blackrod project 
which are expected to be released when these pipelines become operational, in the course of 2025.
15

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
As at March 31, 2025, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May 2026. IPC 
makes quarterly repayments of the France Facility and the amount remaining outstanding under the France Facility as at March 31, 
2025 was MUSD 4.4. An amount of MUSD 3.5 under the France Facility as at March 31, 2025 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, 2025.
Net debt as at March 31, 2025 amounted to MUSD 314. Cash and cash equivalents held amounted to MUSD 140 as at March 31, 
2025.
IPC intends to fund the remaining Blackrod capital expenditure with forecast cash flow generated by its operations, cash on hand 
and Canadian RCF loan drawing if needed.
Working Capital 
As at March 31, 2025, the Group had a working capital balance including cash of USD 83,730 thousand compared to USD 190,771 
thousand as at December 31, 2024. The difference as at March 31, 2025, from December 31, 2024, is mainly a result of the 
decreased cash following capital expenditures on the Blackrod Phase 1 development project and the continuing NCIB program. 
Non-IFRS Measures
In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free 
cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do
not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by 
other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in 
accordance with IFRS.
The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by and 
the financial performance and condition of the Corporation. Management also uses non-IFRS measures internally in order to 
facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s 
ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures 
are important supplemental measures of operating performance because they highlight trends in the core business that may 
not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for 
assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable 
between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties frequently 
use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the purpose of 
presenting information about management’s current expectations and plans relating to the future and readers are cautioned that 
such statements may not be appropriate for other purposes.
“Operating cash flow” is calculated as revenue less production costs including net sales of diluent less current tax. Operating cash 
flow is used to analyze the amount of cash that is being generated available for capital investment and servicing debt.
“Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures 
less general, administration and depreciation expenses before depreciation and less cash financial items. Free cash flow is used 
to analyze the amount of cash that is being generated by the business and that is available for such purposes as repaying debt, 
funding acquisitions and returning capital to shareholders.
“EBITDA” is calculated as net result before financial items, taxes, depletion of oil and gas properties, exploration costs, 
impairment costs and depreciation and adjusted for non-recurring profit/loss on sale of assets and other income.
“Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is 
used to analyze the cash cost of producing the oil and gas volumes.
“Net debt” is calculated as bank loans and bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash 
equivalents less bank loans and bonds. 
16

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
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
2025 2024
Revenue 178,492 206,419 
Production costs and net sales of diluent to third party1 (103,188) (115,745)
Current tax (514) (1,373)
Operating cash flow 74,790 89,301 
1 Includes net sales of diluent to third party amounting to USD 191 thousand for the first quarter of 2025.
Free cash flow
The following table sets out how free cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended March 31
2025 2024
Operating cash flow - see above 74,790 89,301 
Capital expenditures (98,886) (125,256)
Abandonment and farm-in expenditures1 (321) (122)
General, administration and depreciation expenses before depreciation2 (4,358) (3,653)
Cash financial items3 (14,397) (3,581)
Free cash flow (43,172) (43,311)
1  See note 16 to the Financial Statements 
2  Depreciation is not specifically disclosed in the Financial Statements
3  See notes 4 and 5 to the Financial Statements.
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended March 31
2025 2024
Net result 16,231 33,719 
Net financial items 18,855 9,770 
Income tax 4,679 7,746 
Depletion and decommissioning costs 29,016 33,153 
Depreciation of other tangible fixed assets 1,917 2,262 
Exploration and business development costs 31 75
Sale of assets1 (94) –
Depreciation included in general, administration and depreciation 
expenses2 311 295 
EBITDA 70,946 87,020 
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.
17

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Operating costs
The following table sets out how operating costs is calculated: 
USD Thousands
Three months ended March 31
2025 2024
Production costs 103,379 115,745 
Cost of blending (37,726) (45,206)
Change in inventory position 3,500 5,277 
Operating costs 69,153 75,816 
Net cash/(debt)
The following table sets out how net cash/(debt) is calculated: 
USD Thousands March 31, 2025 December 31, 2024
Bank loans (4,449) (5,121)
Bonds1 (450,000) (450,000)
Cash and cash equivalents 140,194 246,593 
Net cash/(debt) (314,255) (208,528)
1  The bond amount represents the redeemable value at maturity (February 2027).  
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, has issued six letters of credit as follows: (a) MCAD 2.6 in respect of its obligations to 
purchase diluent; (b) MCAD 0.9 in respect of its obligations related to the Ferguson asset, increasing by MCAD 0.1 annually to a 
maximum of MCAD 1.0; (c) MCAD 1.3 in respect of pipeline access; (d) MCAD 0.5 in relation to the hedging of electricity prices;
(e) and (f) MCAD 24.5 and MCAD 10.5 respectively in respect of its obligations related to Blackrod pipelines. 
Outstanding Share Data 
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2024, IPC had a total of 126,992,066 common shares issued and outstanding, with no common shares held in 
treasury. From January 1, 2024 to December 4, 2024, IPC purchased and cancelled a total of 7,109,365 common shares under 
the normal course issuer bid/share repurchase program (NCIB). The NCIB was further renewed in Q4 2024 and IPC is entitled to 
purchase up to 7,465,356 common shares over the period of December 5, 2024 to December 4, 2025. During December 2024, 
IPC purchased 823,386 and cancelled 713,230 common shares under the renewed NCIB, for an aggregate of 7,822,595 common 
shares cancelled in 2024. 
As at December 31, 2024, IPC had a total of 119,169,471 common shares issued and outstanding and held 110,156 common 
shares held in treasury.
Over the period of January 1, 2025 to March 31, 2025, IPC purchased  3,670,983 common shares under the NCIB and 211,818 
common shares under certain other exemptions in Canada. All of these purchased common shares, including the common shares 
held in treasury as at December 31, 2024, were cancelled during Q1 2025. As at March 31, 2025, IPC had a total of 115,176,514 
common shares issued and outstanding, with no common shares in treasury.
Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 40,697,533 
common shares in IPC, representing 35.3% of the outstanding common shares as at March 31, 2025.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares.
IPC has 2,944,382 IPC Share Unit Plan awards outstanding as at May 6, 2025 (4,333 awards granted in January 2022, 2,391 
awards granted in July 2022, 2,072 awards granted in January 2023, 919,911 awards granted in February 2023, 3,244 awards 
granted in July 2023, 2,443 awards granted in January 2024, 1,057,235 awards granted in February 2024, 4,328 awards granted in 
July 2024, 5,607 awards granted in January 2025 and 942,818 awards granted in February 2025).
The Corporation is authorized to issue an unlimited number of common shares without par value. The Corporation is also 
authorized to issue an unlimited number of class A preferred shares and an unlimited number of class B preferred shares, issuable 
in series.
18

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
Contractual Obligations and Commitments 
In the normal course of business, the Group has committed to certain payments which are not recognised as liabilities. The
following table summarizes the Group’s commitments in Canada as at March 31, 2025: 
MCAD 2025 2026 2027 2028 2029 Thereafter
Transportation service1 24.6 59.3 88.2 92.8 96.6 1,395.7
Power2 10.9 12.4 12.4 9.8 – –
Total commitments 35.5 71.7 100.6 102.6 96.6 1,395.7
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2045.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from April 1, 2025 to December
31, 2028, an additional 5MWh at a weighted average price of CAD 58.31/MWh from April 1, 2025 to December 31, 2027, and an additional
5MWh at a weighted average price of CAD 46.85/MWh from April 1, 2025 to December 31, 2025.
Material Accounting Policies and Estimates
In connection with the preparation of the consolidated financial statements, the Group’s 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. The assumptions, estimates and judgments are based on historical experience, current trends and other 
factors that management believes to be relevant at the time the consolidated financial statements are prepared. On a regular 
basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that the consolidated 
financial statements are presented fairly in accordance with IFRS Accounting Standards. 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:
Estimates of oil and gas reserves
Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and asset 
retirement obligation. Standard recognized evaluation techniques are used to estimate the proved and probable reserves. These 
techniques take into account the future level of development required to produce the reserves. An independent qualified reserves 
auditor reviews these estimates. Changes in estimates in oil and gas reserves, resulting in different future production profiles, will 
affect the discounted cash flows used in impairment testing, the anticipated date of site decommissioning and restoration and 
the depletion charges in accordance with the unit of production method. Changes in estimates in oil and gas reserves could for 
example result from additional drilling, observation of long-term reservoir performance or changes in economic factors such
as oil price and inflation rates. Significant assumptions developed by management used to determine estimates of proved and 
probable oil and gas reserves include expected production volumes, future oil and gas prices, future development costs and future 
production costs.
Impairment of oil and gas properties 
Impairment tests are performed when there are indicators of impairment. Key assumptions in the impairment models relate to 
prices and costs that are based on forward curves and the long-term corporate assumptions. The impairment test requires the use 
of estimates. For the purpose of determining a potential impairment, the significant assumptions developed by management used 
to determine the recoverable amount include the estimates of oil and gas reserves and the discount rate. These assumptions and 
judgements of management that are based on them are subject to change as new information becomes available. Changes in
economic conditions can also affect the rate used to discount future cash flow estimates and the discount rate applied is reviewed 
throughout the year.
Provision for asset retirement obligations 
Amounts used in recording a provision for asset retirement obligations are estimates based on current legal and constructive 
requirements and current technology and price levels for the removal of facilities and decommissioning. Due to changes in relation 
to these items, the future actual cash outflows in relation to the site decommissioning and restoration can be different. To reflect 
the effects due to changes in legislation, requirements and technology and price levels, the carrying amounts of asset retirement 
obligation 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.
19

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
 
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 recognises the following related parties: associated companies, jointly controlled entities, key management personnel 
and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or 
of its family or of any individual that controls, or has joint control or significant influence over the entity.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with
parties at arm’s length.
During the first quarter of 2025, the Group has not entered into material transactions with related parties.
Financial Risk Management 
As an international oil and gas exploration and production company, IPC is exposed to financial risks such as interest rate risk, 
currency risk, credit risk, liquidity risks as well as the risk related to the fluctuation in oil and gas prices. The Group seeks to control 
these risks through sound management practice and the use of internationally accepted financial instruments, such as oil and gas, 
condensate and electricity price, interest rate or foreign exchange hedges as the case may be. Financial instruments will be solely 
used for the purpose of managing risks in the business. As at March 31, 2025, the Corporation had entered into oil, gas, electricity 
and currency hedges – see below.
Management believes that the cash resources, other current assets and cash flow from operations are sufficient to finance the 
Group’s operations and capital expenditures program over the next year.
Capital Management
The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its 
committed financial liabilities and work program requirements in order to create shareholder value. The Group may put in place 
new bonds or credit facilities, repay debt, or pursue other such restructuring activities as appropriate.
Management of the Corporation will continuously monitor and manage the Group’s capital, liquidity and net debt position in order 
to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility.
Price of Oil and Gas
Prices of oil and gas are affected by the normal economic drivers of supply and demand as well as by financial investors and 
market uncertainty. Factors that influence these prices include operational decisions, prices of competing fuels, natural disasters, 
economic conditions, transportation constraints, political instability or conflicts or actions by major oil exporting countries. Price 
fluctuations will affect the Group’s financial position.
Based on analysis of the circumstances, management assesses the benefits of forward hedging monthly sales contracts for the 
purpose of protecting cash flow. If management believes that a hedging contract will appropriately help manage cash flow then it 
may choose to enter into a commodity price hedge. The Group does not currently have any covenants under its current financing 
facilities to hedge future production.
The Group had oil price sale financial hedges outstanding as at March 31, 2025, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
April 1, 2025 - December 31, 2025 11,700 WTI/WCS Differential USD -14.26/bbl
April 1, 2025 - December 31, 2025 10,000 WTI Sale Swap USD 71.30/bbl
April 1, 2025 - December 31, 2025 2,000 Brent Sale Swap USD 75.78/bbl
The Group had gas price sale financial hedges outstanding as at March 31, 2025, which are summarized as follows:
Period Volume (Gigajoules (GJ) per
day)) Type Average Pricing 
April 1, 2025 - October 31, 2025 20,000 AECO Swap CAD 2.25/GJ
April 1, 2025 - December 31, 2025 10,000 AECO Swap CAD 2.50/GJ
20

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
The Group had electricity financial hedges outstanding as at March 31, 2025, which are summarized as follows:
Period Volume (MWh) Type Average Pricing 
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had 
a negative fair value of USD 1,815 thousand as at March 31, 2025.
Currency Risk
The Group’s policy on currency rate hedging is, in the case of currency exposure, to consider fixing the rate of exchange. The 
Group will take into account the currency exposure, current rates of exchange and market expectations in comparison to historic 
trends and volatility in making the decision to hedge.
The Group entered into currency hedges to purchase:
(i) a total CAD 357.5 million for the period April 2025 to December 2025 at an average rate of CAD 1.36 (sell USD);
(ii) a total EUR 20.25 million for the period April 2025 to December 2025 at an average rate of EUR 1.07 (sell USD);
(iii) a total MYR 102 million for the period April 2025 to December 2025 at an average rate of MYR 4.39 (sell USD).
The outstanding portion of all of the above hedges are treated as effective and changes to the fair value are reflected in other 
comprehensive income. The hedges had a negative fair value of USD 12,484 thousand as at March 31, 2025.
Interest Rate Risk
Interest rate risk is the risk to earnings due to uncertain future interest rates on borrowings. The Group will take into account the 
level of external debt, current interest rates and market expectations in comparison to historic trends and volatility in making the 
decision to hedge. There are currently no interest rate hedges.
Credit Risk
The Group may be exposed to third party credit risk through contractual arrangements with counterparties who buy the Group’s 
hydrocarbon products. The Group’s policy is to limit credit risk by only entering into oil and gas sales agreements with reputable 
and creditworthy oil and gas and trading companies. Where it is determined that there is a credit risk for oil and gas sales, the 
Group’s policy is to require credit enhancement from the purchaser.
The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take 
possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In 
addition, cash is to be held and transacted only through major banks.
RISK FACTORS 
IPC is engaged in the exploration, development and production of oil and gas and is exposed to various operational, environmental,
market and financial risks and uncertainties. For further information and discussion of these risks and uncertainties, please see
IPC’s Annual Information Form for the year ended December 31, 2024 (”AIF”) available on SEDAR+ at www.sedarplus.ca or on
IPC’s website at www.international-petroleum.com. See also “Cautionary Statement Regarding Forward Looking Information” and
“Reserves and Resources Advisory” in this MD&A.
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be 
disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation 
is recorded, processed, summarized and reported within the time periods specified in the securities legislation. Management, 
under the supervision of the Chief Executive Officer and the Chief Financial Officer, is responsible for the design and operation of 
disclosure controls and procedures.
Internal Controls over Financial Reporting
Management is also responsible for the design of the Group’s internal controls over financial reporting in order to provide reasonable 
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in 
accordance with IFRS. However, due to inherent limitations, internal control over financial reporting may not prevent or detect all 
misstatements and fraud. 
There have been no material changes to the Groups internal control over financial reporting during the three months period ended 
March 31, 2025, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial 
reporting. 
Control Framework 
Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control
– Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission 
(COSO). Management concluded that the Corporation’s internal control over financial reporting was effective as of March 31, 2025.  
21

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 
This MD&A contains statements and information which constitute “forward-looking statements“ or “forward-looking information“ 
(within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements“) 
relate to future events, including the Corporation’s future performance, business prospects or opportunities. Actual results may differ 
materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this MD&A 
are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this MD&A, unless 
otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except 
as required by applicable laws.
All statements other than statements of historical fact may be forward-looking statements. Any statements that express or 
involve discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, guidance, budgets, objectives, 
assumptions or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“, 
“continue“, “estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, 
“might“, “should“, “believe“, “budget“ and similar expressions) are not statements of historical fact and may be “forward-looking 
statements“.
Forward-looking statements include, but are not limited to, statements with respect to: 
• 2025 production ranges (including total daily average production), production composition, cash flows, operating costs and 
capital and decommissioning expenditure estimates; 
• Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business 
plans and assumptions regarding the business environment, which are subject to change; 
• IPC’s financial and operational flexibility to navigate the Corporation through periods of volatile commodity prices; 
• The ability to fully fund future expenditures from cash flows and current borrowing capacity; 
• IPC’s intention and ability to continue to implement its strategies to build long-term shareholder value; 
• The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth; 
• The continued facility uptime and reservoir performance in IPC’s areas of operation; 
• Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing, 
regulatory approvals, third party commercial arrangements, breakeven oil prices and net present values;
• Current and future production performance, operations and development potential of the Onion Lake Thermal, Suffield, 
Brooks, Ferguson and Mooney operations, including the timing and success of future oil and gas drilling and optimization 
programs; 
• The potential improvement in the Canadian oil egress situation and IPC’s ability to benefit from any such improvements;
• The ability to maintain current and forecast production in France and Malaysia; 
• The intention and ability of IPC to acquire further common shares under the NCIB, including the timing of any such purchases;
• The return of value to IPC’s shareholders as a result of the NCIB;
• IPC’s ability to implement its greenhouse gas (GHG) emissions intensity and climate strategies and to achieve its net GHG 
emissions intensity reduction targets;
• IPC’s ability to implement projects to reduce net emissions intensity, including potential carbon capture and storage;
• Estimates of reserves and contingent resources; 
• The ability to generate free cash flows and use that cash to repay debt;
• IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the 
Corporation; 
• IPC’s ability to identify and complete future acquisitions;
• Expectations regarding the oil and gas industry in Canada, Malaysia and France, including assumptions regarding future 
royalty rates, regulatory approvals, legislative changes, 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 potential impact of tariffs implemented in 2025 by the U.S. and Canadian governments and that 
other than the tariffs that have been implemented, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, or 
imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any 
other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and 
natural gas; prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future 
well production rates and reserve and contingent resource volumes; operating costs; our ability to maintain our existing credit 
ratings; our ability to achieve our performance targets; the timing of receipt of regulatory approvals; the performance of existing 
wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted 
capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful 
completion of acquisitions and dispositions and that we will be able to implement our standards, controls, procedures and policies 
in respect of any acquisitions and realize the expected synergies on the anticipated timeline or at all; the benefits of acquisitions; 
the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally; the 
22

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
availability and cost of financing, labour and services; our intention to complete share repurchases under our normal course issuer 
bid program, including the funding of such share repurchases, existing and future market conditions, including with respect to the 
price of our common shares, and compliance with respect to applicable limitations under securities laws and regulations and stock 
exchange policies; and the ability to market crude oil, natural gas and natural gas liquids successfully.
Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are 
reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they 
will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve 
inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors 
and risks.
These include, but are not limited to: 
• General global economic, market and business conditions;
• The risks associated with the oil and gas industry in general such as operational risks in development, exploration and 
production;
• Delays or changes in plans with respect to exploration or development projects or capital expenditures;
• The uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses;
• Health, safety and environmental risks;
• Commodity price fluctuations;
• Interest rate and exchange rate fluctuations;
• Marketing and transportation;
• Loss of markets;
• Environmental and climate-related risks;
• Competition;
• Innovation and cybersecurity risks related to our systems, including our costs of addressing or mitigating such risks;
• The ability to attract, engage and retain skilled employees
• Incorrect assessment of the value of acquisitions;
• Failure to complete or realize the anticipated benefits of acquisitions or dispositions;
• The ability to access sufficient capital from internal and external sources;
• Failure to obtain required regulatory and other approvals;
• Geopolitical conflicts, including the war between Ukraine and Russia and the conflict in the Middle East, and their potential 
impact on, among other things, global market conditions
• Political or economic developments, including, without limitation, the risk that (i) one or both of the U.S. and Canadian 
governments increases the rate or scope of tariffs implemented in 2025, or imposes new tariffs on the import of goods from 
one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction 
or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the 
tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, 
U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Corporation; and
• Changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations. 
Readers are cautioned that the foregoing list of factors is not exhaustive. See also “Risk Factors”.
Estimated production and FCF generation are based on IPC’s current business plans over the periods of 2025 to 2029 and 
2030 to 2034, less net debt of USD 209 million as at December 31, 2024, with assumptions based on the reports of IPC’s 
independent reserves evaluators, and including certain corporate adjustments relating to estimated general and administration 
costs and hedging, and excluding shareholder distributions and financing costs. Assumptions include average net production of 
approximately 57 Mboepd over the period of 2025 to 2029, average net production of approximately 63 Mboepd over the period of 
2030 to 2034, average Brent oil prices of USD 75 to 95 per bbl escalating by 2% per year, and average Brent to Western Canadian 
Select differentials and average gas prices as estimated by IPC’s independent reserves evaluator and as further described in the 
AIF . IPC’s current business plans and assumptions, and the business environment, are subject to change. Actual results may differ 
materially from forward-looking estimates and forecasts.
Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the 
Financial Statements, the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2024 (see “Cautionary 
Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk Factors”) and other reports 
on file with applicable securities regulatory authorities, including previous financial reports, management’s discussion and analysis 
and material change reports, which may be accessed through the SEDAR+ website (www.sedarplus.ca) or IPC’s website (www. 
international-petroleum.com).
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.
23

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

Management’s Discussion and Analysis
For the three months ended March 31, 2025
RESERVES AND RESOURCES ADVISORY 
This MD&A contains references to estimates of gross and net reserves and resources attributed to the Corporation’s oil and gas 
assets. Gross reserves/resources are the working interest (operating or non-operating) share before deduction of royalties and 
without including any royalty interests. Net reserves/resources are the working interest (operating or non-operating) share after 
deduction of royalty obligations, plus royalty interests in reserves/resources, and in respect of PSCs in Malaysia, adjusted for cost 
and profit oil. Unless otherwise indicated, reserves/resource volumes are presented on a gross basis.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in 
Canada are effective as of December 31, 2024, and are included in the reports prepared by Sproule Associates Limited (Sproule), 
an independent qualified reserves evaluator, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and 
Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule’s December 
31, 2024 price forecasts.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in 
France and Malaysia are effective as of December 31, 2024, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), 
an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 
31, 2024 price forecasts.
The price forecasts used in the Sproule and ERCE reports, are available on the website of Sproule (sproule. com) and are contained 
in the AIF . These price forecasts are as at December 31, 2024 and may not be reflective of current and future forecast commodity 
prices.
The reserve life index (RLI) is calculated by dividing the 2P reserves of 493 MMboe as at December 31, 2024, by the mid-point of 
the 2025 CMD production guidance of 43,000 to 45,000 boepd. 
The product types comprising the 2P reserves and contingent resources described in this MD&A are contained in the AIF . See also 
“Supplemental Information regarding Product Types” below. Light, medium and heavy crude oil and bitumen reserves/ resources 
disclosed in this MD&A include solution gas and other by-products.
“2P reserves“ means proved plus probable reserves. “Proved reserves“ are those reserves that can be estimated with a high 
degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved 
reserves. “Probable reserves“ are those additional reserves that are less certain to be recovered than proved reserves. It is equally 
likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable 
reserves.
Each of the reserves categories reported (proved and probable) may be divided into developed and undeveloped categories. 
“Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if 
facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) 
to put the reserves on production. The developed category may be subdivided into producing and non-producing. “Developed
producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the 
estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of 
resumption of production must be known with reasonable certainty. “Developed non-producing reserves” are those reserves that 
either have not been on production, or have previously been on production, but are shut-in, and the date of resumption
of production is unknown. “Undeveloped reserves” are those reserves expected to be recovered from known accumulations 
where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of 
production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known 
accumulations using established technology or technology under development, but which are not currently considered to be 
commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion 
of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be 
resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political, 
and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered 
recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in
accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or 
characterized by their economic status.
There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a 
classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity 
that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best 
estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered 
will equal or exceed the best estimate.
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 
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Management’s Discussion and Analysis
For the three months ended March 31, 2025
contingencies can be clearly defined. Chance of development is the probability of a project being commercially viable. Where 
risked resources are presented, they have been adjusted based on the chance of development by multiplying the unrisked values 
by the chance of development.
References to “unrisked“ contingent resources volumes means that the reported volumes of contingent resources have not 
been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook for 
contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies 
required for the re-classification of the contingent resources as reserves being resolved. Therefore, unrisked reported volumes 
of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such 
resources.
The contingent resources reported in this MD&A are estimates only. The estimates are based upon a number of factors and 
assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and 
commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil 
and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks 
and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is 
uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this MD&A.
2P reserves and contingent resources included in the reports prepared by Sproule and ERCE have been aggregated by IPC. 
Estimates of reserves, resources and future net revenue for individual properties may not reflect the same level of confidence 
as estimates of reserves, resources and future net revenue for all properties, due to aggregation. This MD&A contains estimates 
of the net present value of the future net revenue from IPC’s reserves and contingent resources. The estimated values of future 
net revenue disclosed in this MD&A do not represent fair market value. There is no assurance that the forecast prices and cost 
assumptions used in the reserve and resources evaluations will be attained and variances could be material.
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.
Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel (bbl) 
is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value 
equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and 
crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an 
indication of value.
Supplemental Information regarding Product Types
The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily 
production figures provided in this document:
Heavy Crude Oil 
(Mbopd)
Light and Medium 
Crude Oil (Mbopd)
Conventional Natural Gas
(per day)
Total
(Mboepd)
Three months ended
March 31, 2025 23.2 6.5 88.2 MMcf                     
(14.7 Mboe) 44.4
March 31, 2024 24.9 7.9 96.0 MMcf                     
(16.0 Mboe) 48.8
Year ended December 31, 2024
December 31, 2024 23.9 7.7 95.1MMcf                     
(15.8 Mboe) 47.4
This MD&A also makes reference to IPC’s forecast total average daily production of 43,000 to 45,000 boepd for 2025. IPC 
estimates that approximately 52% of that production will be comprised of heavy oil, approximately 15% will be comprised of light 
and medium crude oil and approximately 33% will be comprised of conventional natural gas.
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Management’s Discussion and Analysis
For the three months ended March 31, 2025
OTHER SUPPLEMENTARY INFORMATION
Abbreviations
CAD  Canadian dollar
MCAD  Million Canadian dollar
EUR  Euro
USD  US dollar
MUSD  Million US dollar
MYR  Malaysian Ringgit
FPSO  Floating Production Storage and Offloading (facility)
Oil related terms and measurements
AECO   The daily average benchmark price for natural gas at the AECO hub in southeast Alberta                                                                            
AESO  Alberta Electric System Operator
API   An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale
ASP   Alkaline surfactant polymer (an EOR process)
bbl   Barrel (1 barrel = 159 litres)
boe   Barrels of oil equivalents
boepd   Barrels of oil equivalents per day
bopd   Barrels of oil per day
Bcf  Billion cubic feet
C5  Condensate
CO2e  Carbon dioxide equivalents, including carbon dioxide, methane and nitrous oxide
Empress   The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border
EOR   Enhanced Oil Recovery
GJ  Gigajoules
Mbbl   Thousand barrels
MMbbl   Million barrels
Mboe   Thousand barrels of oil equivalents 
Mboepd   Thousand barrels of oil equivalents per day
Mbopd   Thousand barrels of oil per day
MMboe   Million barrels of oil equivalents
MMbtu   Million British thermal units
Mcf   Thousand cubic feet
Mcfpd  Thousand cubic feet per day
MMcf   Million cubic feet
MW  Mega watt
MWh  Mega watt per hour
NGL   Natural gas liquid
SAGD   Steam assisted gravity drainage
WTI   West Texas Intermediate
WCS   Western Canadian Select
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Management’s Discussion and Analysis
For the three months ended March 31, 2025
DIRECTORS
C. Ashley Heppenstall
Director, Chair
London, England
William Lundin
Director, President and Chief Executive Officer
Coppet, Switzerland
Chris Bruijnzeels
Director
Abcoude, The Netherlands
Donald K. Charter
Director
Toronto, Ontario, Canada
Lukas (Harry) H. Lundin
Director
Toronto, Ontario, Canada
Emily Moore
Director
Toronto, Ontario, Canada
Mike Nicholson
Director
Monaco
Deborah Starkman
Director
Toronto, Ontario, Canada
OFFICERS
William Lundin
President and Chief Executive Officer
Coppet, Switzerland
Christophe Nerguararian
Chief Financial Officer
Geneva, Switzerland
Nicki Duncan
Chief Operating Officer
Geneva, Switzerland
Jeffrey Fountain
General Counsel and Corporate Secretary
Geneva, Switzerland
Rebecca Gordon
Senior Vice President Corporate Planning and 
Investor Relations
Geneva, Switzerland 
Chris Hogue
Senior Vice President, Canada
Calgary, Alberta, Canada
Ryan Adair
Vice President Asset Management and
Corporate Planning, Canada
Calgary, Alberta, Canada
Curtis White
Vice President Commercial, Canada
Calgary, Alberta, Canada
MEDIA AND INVESTOR RELATIONS
Robert Eriksson 
Stockholm, Sweden
CORPORATE OFFICE
Suite 2800, 1055 Dunsmuir Street Vancouver, 
British Columbia
V7X 1L2 Canada
Telephone: +1 604 689 7842
Website: www.international-petroleum.com
OPERATIONS OFFICE
5 Chemin de la Pallanterie
1222 Vésenaz
Switzerland
Telephone: +41 22 595 10 50
E-mail: info@international-petroleum.com
REGISTERED AND RECORDS OFFICE
Suite 3500, 1133 Melville Street 
Vancouver, British Columbia
V6E 4E5 Canada
INDEPENDENT AUDITORS
PricewaterhouseCoopers LLP , Canada
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta, and Toronto, Ontario
STOCK EXCHANGE LISTINGS
Toronto Stock Exchange and NASDAQ Stockholm 
Trading Symbol: IPCO
27

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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□