Kvartalsrapport Q2 2023

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Q2
International Petroleum Corporation
Interim Condensed Consolidated
Financial Statements
For the three and six months ended June 30, 2023

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2
Contents
Interim Condensed Consolidated Statement of Operations  3
Interim Condensed Consolidated Statement of Comprehensive Income  4
Interim Condensed Consolidated Balance Sheet  5
Interim Condensed Consolidated Statement of Cash Flow 6
Interim Condensed Consolidated Statement of Changes in Equity 7
Notes to the Interim Condensed Consolidated Financial Statements 8
Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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Interim Condensed Consolidated Statement of Operations
For the three and six months ended June 30, 2023 and 2022, UNAUDITED
 Three months ended June 30 Six months ended June 30
USD Thousands Note 2023 2022 2023 2022
Revenue 2 205,564 315,540 398,080 575,322
Cost of sales
Production costs 3 (116,597) (118,151) (234,124) (228,700)
Depletion and decommissioning costs 7 (33,362) (31,830) (39,801) (59,782)
Depreciation of other tangible fixed assets 9 (2,436) (3,021) (4,994) (5,101)
Exploration and business development costs (422) (829) (2,031) (930)
Gross profit 2 52,747 161,709 117,130 280,809 
General, administration and depreciation expenses (4,158) (3,743) (8,352) (7,916)
Profit before financial items 48,589 157,966 108,778 272,893 
Finance income 4 4,335 556 9,259 628 
Finance costs 5 (11,290) (15,853) (21,229) (22,532)
Net financial items (6,955) (15,297) (11,970) (21,904)
Profit before tax 41,634 142,669 96,808 250,989
Income tax expense 6 (9,609) (37,452) (25,220) (64,950)
Net result 32,025 105,217 71,588 186,039 
Net result attributable to:
Shareholders of the Parent Company 32,017 105,195 71,574 186,002 
Non-controlling interest 8 22 14 37 
32,025 105,217 71,588 186,039 
Earnings per share – USD1 15 0.24 0.70 0.53 1.22
Earnings per share fully diluted – USD1 15 0.24 0.68 0.52 1.19
1  Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the interim condensed consolidated financial statements

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Interim Condensed Consolidated Statement of Comprehensive Income
For the three and six months ended June 30, 2023 and 2022, UNAUDITED
Three months ended June 30 Six months ended June 30
USD Thousands Note 2023 2022 2023 2022
Net result 32,025 105,217 71,588 186,039
Other comprehensive income
Items that may be reclassified to profit or loss:
Reclassification of hedging (gains) / losses to profit
or loss 2 (1,531) 8,600 (10,115) 8,856
Gains / (losses) on cash flow hedges 3,954 16,411 8,613 3,293
Income tax relating to these items (641) (6,252) 345 (3,005)
Currency translation adjustments 15,734 (22,857) 16,911 (17,771)
Total comprehensive income 49,541 101,119 87,342 177,412
Total comprehensive income attributable to:
Shareholders of the Parent Company 49,541 101,105 87,333 177,385
Non-controlling interest – 14 9 27
49,541 101,119 87,342 177,412
See accompanying notes to the interim condensed consolidated financial statements

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Interim Condensed Consolidated Balance Sheet
As at June 30, 2023 and December 31, 2022, UNAUDITED
USD Thousands Note June 30, 2023 December 31, 2022
ASSETS
Non-current assets
Oil and gas properties 7 1,122,628 963,375
Other tangible fixed assets 9 28,895 33,374
Right-of-use assets 3,155 1,217
Deferred tax assets 6 1,522 1,960
Derivative instruments 19 3,144 –
Other assets 10 42,324 41,125
Total non-current assets 1,201,668 1,041,051
Current assets
Inventories 11 28,605 15,958
Trade and other receivables 12 103,627 123,609
Derivative instruments 19 9,502 11,741
Current tax receivables 2,352 18
Cash and cash equivalents 13 374,177 487,240
Total current assets 518,263 638,566
TOTAL ASSETS 1,719,931 1,679,617
LIABILITIES
Non-current liabilities
Financial liabilities 16 7,117 8,711
Bonds 16 295,999 295,440
Lease liabilities 2,398 507
Provisions 17 239,321 203,389
Deferred tax liabilities 6 53,562 56,334
Derivative instruments 19 401 –
Total non-current liabilities 598,798 564,381
Current liabilities
Trade and other payables 18 124,550 118,726
Financial liabilities 16 3,512 3,431
Derivative instruments 19 3,033 1,155
Current tax liabilities 2,854 17,793
Lease liabilities 789 752
Provisions 17 7,596 8,048
Total current liabilities 142,334 149,905
EQUITY
Shareholders’ equity 978,630 965,140
Non-controlling interest 169 191
Net shareholders’ equity 978,799 965,331
TOTAL EQUITY AND LIABILITIES 1,719,931 1,679,617
Approved by the Board of Directors
(Signed) C. Ashley Heppenstall    (Signed) Mike Nicholson
Director       Director
See accompanying notes to the interim condensed consolidated financial statements

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Interim Condensed Consolidated Statement of Cash Flow
For the three and six months ended June 30, 2023 and 2022, UNAUDITED
Three months ended June 30 Six months ended June 30
USD Thousands Note 2023 2022 2023 2022
Cash flow from operating activities
Net result 32,025 105,217 71,588 186,039
Adjustments for non-cash related items:
Depletion, depreciation and amortization 7,9 36,199 35,243 45,579 65,678
Income tax 6 9,609 37,452 25,220 64,950 
Amortization of capitalized financing fees 5 338 317 781 2,642
Foreign currency exchange 5 1,491 7,102 2,347 4,043 
Interest expense 5 5,455 5,481 10,804 9,515
Interest income 4 (4,335) (549) (9,259) (604)
Unwinding of asset retirement obligation discount 5 3,474 2,729 6,542 5,489
Share-based costs 2,353 2,268 4,940 3,999 
Other 237 163 415 413 
Cash flow generated from operations (before 
working capital adjustments and income taxes) 86,846 195,423 158,957 342,164
Changes in working capital  7,949 (2,892) (6,644) (28,379)
Decommissioning costs paid 17 (3,160) (2,435) (4,371) (3,762)
Other payments 17 (574) – (864) (598)
Income taxes received / (paid) (22,490) (7,915) (26,074) (8,889)
Interest received 2,800 546 7,765 601 
Interest paid (14) (52) (10,961) (498)
Net cash flow from operating activities 71,357 182,675 117,808 300,639
Cash flow used in investing activities
Investment in oil and gas properties 7 (58,822) (29,788) (107,060) (68,141)
Acquisition of Cor4 net of cash acquired 8 (239) – (59,419) – 
Investment in other tangible fixed assets 9 (245) (40) (417) (88)
Net cash (outflow) from investing activities (59,306) (29,828) (166,896) (68,229)
Cash flow from financing activities
Borrowings / (Repayments) 16 (880) 346 (1,736) (98,396)
Bonds issuance 16 – – – 300,000
Paid financing fees 16 – – (507) (5,583)
Financing of 2022 Substantial Issuer Bid – (99,650) – (99,650)
Repurchase of own shares 14 (14,325) – (60,155) (21,029)
Other payments (259) (166) (445) (350)
Net cash (outflow) from financing activities  (15,464) (99,470)  (62,843)  74,992
Change in cash and cash equivalents (3,413) 53,377 (111,931) 307,402
Cash and cash equivalents at the beginning of the 
period 378,466 272,033 487,240 18,810
Currency exchange difference in cash and cash 
equivalents (876) 2,450 (1,132) 1,648
Cash and cash equivalents at the end of the period 374,177 327,860 374,177 327,860
   
See accompanying notes to the interim condensed consolidated financial statements

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Interim Condensed Consolidated Statement of Changes in Equity
For the three and six months ended June 30, 2023 and 2022, 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, 2023 338,719 635,895 (31,292) 11,349 7,958 2,511 965,140 191 965,331
Net result – 71,574 – – – – 71,574 14 71,588
Acquisition of Cor41 – – – – 881 – 881 – 881
Cash flow hedge – – – – (2,038) – (2,038) – (2,038)
Currency translation difference – – 16,771 17 128 – 16,916 (5) 16,911
Total comprehensive income – 71,574 16,771 17 (1,029) – 87,333 9 87,342
Dividend distribution – – – – – – – (31) (31)
Repurchase of own shares2 (60,156) – – – – – (60,156) – (60,156)
Share based costs – – – 17,393 – – 17,393 – 17,393
Share based payments3 (12,931) – – (18,149) – – (31,080) – (31,080)
Balance at June 30, 2023 265,632 707,469 (14,521) 10,610 6,929 2,511 978,630 169 978,799
1  See Note 8
2  See Note 14
3 The third instalment of IPC RSP 2020 awards, the second instalment of IPC RSP 2021 awards, the first instalment of IPC RSP 2022 awards and 
the IPC PSP 2020 awards vested on January 31, 2023, at a price of CAD 14.26 per award. The difference between the value at vesting date 
and at grant (respectively CAD 4.35 per award, CAD 4.07 per award, CAD 9.09 per award and CAD 3.65 per award) was offset against share 
premium. 
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, 2022 528,764 298,212 11,291 9,700 874 (1,455) 847,386 157 847,543
Net result – 186,002 – – – – 186,002 37 186,039
Cash flow hedge – – – – 9,144 – 9,144 – 9,144
Currency translation difference – – (17,532) (245) 16 – (17,761) (10) (17,771)
Total comprehensive income – 186,002 (17,532) (245) 9,160 – 177,385 27 177,412
Repurchase of own shares1 (21,029) – – – – – (21,029) – (21,029)
Share based payments (2,432) – – 2,034 – – (398) – (398)
Balance at June 30, 2022 505,303 484,214 (6,241) 11,489 10,034 (1,455) 1,003,344 184 1,003,528
1 See Note 14
See accompanying notes to the interim condensed consolidated financial statements.

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Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED
1. CORPORATE INFORMATION
A. The Group
International Petroleum Corporation (“IPC” or the “Corporation” and, together with its subsidiaries, the “Group”) is in the business 
of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production assets and development 
projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange (“TSX”) in Canada and the Nasdaq Stockholm 
Exchange in Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada under the Business Corporations 
Act. The address of its registered office is Suite 2600, 595 Burrard Street, P .O. Box 49314, Vancouver, BC V7X 1L3, Canada and its 
business address is Suite 2000, 885 West Georgia Street, Vancouver,  BC V6C 3E8, Canada.
On March 3, 2023, IPC completed the acquisition (the “Cor4 acquisition”) of all of the issued and outstanding shares of Cor4 Oil 
Corp. (“Cor4”). On June 1, 2023, Cor4 was amalgamated into IPC Canada Ltd.
B. Basis of preparation
The unaudited interim condensed consolidated financial statements have been prepared in accordance with International
Accounting Standard 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting 
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The financial statements should be 
read in conjunction with IPC’s annual consolidated financial statements for the year ended December 31, 2022, which have been 
prepared in accordance with IFRS as issued by the IASB.
These unaudited interim consolidated financial statements are presented in United States Dollars (USD), which is the Group’s 
presentation and functional currency. The unaudited interim consolidated financial statements have been prepared on a historical 
cost basis, except for items that are required to be accounted for at fair value as detailed in the Group’s accounting policies. 
Intercompany transactions and balances have been eliminated. Certain comparative figures have been reclassified to conform with 
the financial statements presentation in the current year.
The unaudited interim condensed consolidated financial statements have been approved by the Board of Directors of IPC and 
authorized for issuance on August 1, 2023. 
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, 2022. 
C. Going concern
The unaudited interim condensed consolidated financial statements for the six months ended June 30, 2023, 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.
D. Changes in accounting policies and disclosures
During the six months ended June 30, 2023, the Group applied the amended accounting standards, interpretations and annual 
improvement points that are effective as of January 1, 2023.

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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, exploration and evaluation costs and gross 
profit. 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.
Three months ended - June 30, 2023
USD Thousands Canada Malaysia France Other Total
Crude oil 172,139 22,105 18,027 – 212,271
NGLs 278 – – – 278
Gas 15,376 – – – 15,376
Net sales of oil and gas 187,793 22,105 18,027 – 227,925
Change in under/over lift position – – 1,823 – 1,823
Royalties (25,075) – (862) – (25,937)
Hedging settlement 1,531 – – – 1,531
Other operating revenue 1 – 221 – 222
Revenue 164,250 22,105 19,209 – 205,564
Operating costs (65,149) (7,271) (7,867) – (80,287)
Cost of blending (40,870) – – – (40,870)
Change in inventory position 376 4,747 (563) – 4,560
Depletion and decommissioning costs (24,215) (5,551) (3,596) – (33,362)
Depreciation of other tangible fixed assets – (2,436) – – (2,436)
Exploration and business development costs (3) – (9) (410) (422)
Gross profit/(loss) 34,389 11,594 7,174 (410) 52,747
Three months ended - June 30, 2022
USD Thousands Canada Malaysia France Other Total
Crude oil 245,662 32,630 27,741 – 306,033
NGLs 235 – – – 235
Gas 51,229 – – – 51,229
Net sales of oil and gas 297,126 32,630 27,741 – 357,497
Change in under/over lift position – – 4,668 – 4,668
Royalties (36,346) – (1,863) – (38,209)
Hedging settlement (8,600) – – – (8,600)
Other operating revenue – – 184 – 184
Revenue 252,180 32,630 30,730 – 315,540
Operating costs (54,964) (6,822) (8,901) – (70,687)
Cost of blending (57,639) – – – (57,639)
Change in inventory position 1,505 8,547 123 – 10,175
Depletion and decommissioning costs (18,918) (9,713) (3,199) – (31,830)
Depreciation of other tangible fixed assets – (3,021) – – (3,021)
Exploration and business development costs 97 – – (926) (829)
Gross profit/(loss) 122,261 21,621 18,753 (926) 161,709
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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Six months ended - June 30, 2023
USD Thousands Canada Malaysia France Other Total
Crude oil 319,870 39,776 33,158 – 392,804
NGLs 468 – – – 468
Gas 35,859 – – – 35,859
Net sales of oil and gas 356,197 39,776 33,158 – 429,131
Change in under/over lift position – – 4,493 – 4,493
Royalties (43,740) – (2,336) – (46,076)
Hedging settlement 10,115 – – – 10,115
Other operating revenue 7 – 410 – 417
Revenue 322,579 39,776 35,725 – 398,080
Operating costs (124,680) (15,447) (15,605) – (155,732)
Cost of blending (88,687) – – – (88,687)
Change in inventory position (46) 10,619 (278) – 10,295
Depletion and decommissioning costs 1 (21,692) (11,380) (6,729) – (39,801)
Depreciation of other tangible fixed assets – (4,994) – – (4,994)
Exploration and business development costs (834) – (9) (1,188) (2,031)
Gross profit/(loss) 86,640 18,574 13,104 (1,188) 117,130
1  In Canada, includes an adjustment in the first quarter of 2023 for accelerated decommissioning activities funded by a non-cash site rehabilitation 
program. 
Six months ended - June 30, 2022
USD Thousands Canada Malaysia France Other Total
Crude oil 436,892 68,644 61,400 – 566,936
NGLs 462 – – – 462
Gas 81,445 – – – 81,445
Net sales of oil and gas 518,799 68,644 61,400 – 648,843
Change in under/over lift position – – (1,445) – (1,445)
Royalties (60,334) – (3,387) – (63,721)
Hedging settlement (8,856) – – – (8,856)
Other operating revenue 101 – 400 – 501
Revenue 449,710 68,644 56,968 – 575,322
Operating costs (107,401) (16,408) (18,339) – (142,148)
Cost of blending (100,280) – – – (100,280)
Change in inventory position 2,433 10,683 612 – 13,728
Depletion and decommissioning costs (36,777) (16,402) (6,603) – (59,782)
Depreciation of other tangible fixed assets – (5,101) – – (5,101)
Exploration and business development costs 97 – – (1,027) (930)
Gross profit/(loss) 207,782 41,416 32,638 (1,027) 280,809
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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3. PRODUCTION COSTS
Three months ended June 30 Six months ended June 30
USD Thousands 2023 2022 2023 2022
Cost of operations 69,378 60,053 134,152 120,757
Tariff and transportation expenses 9,559 9,193 19,058 18,521 
Direct production taxes 1,350 1,441 2,522 2,870
Operating costs 80,287 70,687 155,732 142,148
Cost of blending1 40,870 57,639 88,687 100,280 
Change in inventory position (4,560) (10,175) (10,295) (13,728)
Total production costs 116,597 118,151 234,124 228,700
1  In Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. Cost of blending represents the contracted 
purchase of diluent used for blending.
4. FINANCE INCOME
Three months ended June 30 Six months ended June 30
USD Thousands 2023 2022 2023 2022
Interest income 4,335 549 9,259 604 
Other financial income – 7 – 24 
Total finance income 4,335 556 9,259 628 
5. FINANCE COSTS
Three months ended June 30 Six months ended June 30
USD Thousands 2023 2022 2023 2022
Foreign exchange loss, net 1,491 7,102 2,347 4,043 
Interest expense 5,455 5,481 10,804 9,515 
Unwinding of asset retirement obligation discount 3,474 2,729 6,542 5,489 
Amortization of loan fees 59 38 223 2,177 
Amortization of bond fees 279 279 558 465 
Loan commitment fees 186 95 274 354 
Other financial costs 346 129 481 489 
Total finance costs 11,290 15,853 21,229 22,532 
6. INCOME TAX
Three months ended June 30 Six months ended June 30
USD Thousands 2023 2022 2023 2022
Current tax (4,595) (4,874) (8,586) (8,997)
Deferred tax (5,014) (32,578) (16,634) (55,953)
Total tax recovery / (expense) (9,609) (37,452) (25,220) (64,950)
The deferred tax amount arises primarily where there is a difference in depletion for tax and accounting purposes. The deferred tax 
charge in the statement of operations for the current period mainly relates to the tax profit incurred and the tax losses used during 
the first six months of 2023.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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Specification of deferred tax assets and tax liabilities1
USD Thousands June 30, 2023 December 31, 2022
Unused tax loss carry forward 37,116 32,815
Other 5,272 5,841
Deferred tax assets 42,388 38,656
Accelerated allowances 92,053 90,400
Other 2,375 2,630
Deferred tax liabilities 94,428 93,030
Deferred taxes, net (52,040) (54,374)
1  The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the 
balance sheet when they relate to the same jurisdiction.
The deferred tax liabilities consist of accelerated allowances, being the difference between the book and the tax value of oil and 
gas properties and site restoration provisions. The deferred tax liabilities will be released over the life of the oil and gas assets as 
the book value is depleted for accounting purposes. 
Deferred tax assets in relation to tax loss carried forwards are only recognized in so far that there is a reasonable certainty as to
the timing and the extent of their realization. The recognized unused tax loss carry forward mainly relates to Canada. The Group
has concluded that the deferred assets will be recoverable using the estimated future taxable income based on the approved
business plans and budgets.
7. OIL AND GAS PROPERTIES
USD Thousands June 30, 2023 December 31, 2022
Exploration and Evaluation Assets                 – 4,764
Property, Plant and Equipment 1,122,628 958,611
Oil and gas properties 1,122,628 963,375
Exploration and Evaluation Assets
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 – – 4,764 4,764
Additions – – 9 9
Write-off – – (9) (9)
Reclassification – – (4,854) (4,854)
Currency translation adjustments – – 90 90
Net book value June 30, 2023 – – – –
USD Thousands Canada Malaysia France Total
Cost
January 1, 2022 12,751 181 5,105 18,037
Additions1 (802) 149 4 (649)
Reclassification (11,974) (330) – (12,304)
Currency translation adjustments 25 – (345) (320)
Net book value December 31, 2022 – – 4,764 4,764
1 Net revenues on appraisal projects are being offset against capitalized costs of Exploration and Evaluation Assets.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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Property, Plant and Equipment
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 1,089,789 566,606 399,237 2,055,632
Acquisition of Cor4 - See Note 8 72,242 – – 72,242
Additions 91,190 1,262 14,599 107,051
Reclassification – – 4,854 4,854
Currency translation adjustments 25,693 – 7,484 33,177
June 30, 2023 1,278,914 567,868 426,174 2,272,956
Accumulated depletion
January 1, 2023 (323,273) (485,034) (288,714) (1,097,021)
Depletion charge for the period (45,815) (11,380) (6,729) (63,924)
Other1 22,857 – – 22,857
Currency translation adjustments (6,869) – (5,371) (12,240)
June 30, 2023 (353,100) (496,414) (300,814) (1,150,328)
Net book value June 30, 2023 925,814 71,454 125,360 1,122,628
1  In Canada, includes an adjustment in the first quarter of 2023 for accelerated decommissioning activities funded by a non-cash site rehabilitation 
program. 
USD Thousands Canada Malaysia France Total
Cost
January 1, 2022 1,021,944 534,443 408,211 1,964,598
Additions 118,762 27,305 12,244 158,311
Change in estimates 5,231 4,528 2,182 11,941
Reclassification 11,974 330 – 12,304
Currency translation adjustments (68,122) – (23,400) (91,522)
December 31, 2022 1,089,789 566,606 399,237 2,055,632
Accumulated depletion
January 1, 2022 (267,585) (450,347) (293,132) (1,011,064)
Depletion charge for the period (75,077) (34,687) (12,277) (122,041)
Currency translation adjustments 19,389 – 16,695 36,084
December 31, 2022 (323,273) (485,034) (288,714) (1,097,021)
Net book value December 31, 2022 766,516 81,572 110,523 958,611
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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8. COR4 ACQUISITION
On March 3, 2023, IPC completed the acquisition of all of the issued and outstanding shares of Cor4. At such date, Cor4 became 
an indirect, wholly-owned subsidiary of IPC. On June 1, 2023, Cor4 was amalgamated into IPC Canada Ltd.
The Cor4 acquisition has been accounted for as a business combination with IPC being the acquirer, and in accordance with IFRS
3 Business Combinations, the assets acquired and liabilities assumed have been recorded at their fair values. 
The total cash consideration paid, after preliminary closing adjustments, amounted to USD 62.2 million (CAD 84.7 million).
The amounts recognized in respect of the identifiable assets acquired and liabilities assumed are as set out in the table below:
USD Thousands
Cash  2,792 
Trade and other receivables  7,671 
Prepaid expenses and deposits  2,417
Fair value of risk management assets  1,144 
Deferred tax assets  19,334 
Right-of-use assets  109 
Property, plant and equipment  72,242
Accounts payable and accrued liabilities  (12,623)
Right-of-use liabilities  (109)
Decommissioning liabilities  (29,885)
Mark-To-Market (“MTM”) reserve in equity  (881)
Total Consideration 62,211
Settled by:
Cash payment 62,211
The Corporation performed a preliminary purchase price allocation for the Cor4 acquisition. The amounts disclosed above were 
determined provisionally pending the finalization of the valuation for those assets and liabilities. Up to twelve months from the 
effective date of the Cor4 acquisition, further adjustments may be made to the fair values assigned to the identifiable assets 
acquired and liabilities assumed. 
Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during the first six 
months of 2023.
Decommissioning liabilities
The fair value of the decommissioning liability at the acquisition date was based on the estimated future cash flows to 
decommission the acquired oil and natural gas properties at the end of their useful life. The discount rate used to determine the 
net present value of the decommissioning obligation was a credit risk adjusted rate of 8%.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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9. OTHER TANGIBLE FIXED ASSETS
USD Thousands FPSO Other Total
Cost
January 1, 2023 204,853 9,779 214,632
Additions – 417 417
Currency translation adjustments 400 159 559
June 30, 2023 205,253 10,355 215,608
Accumulated depreciation
January 1, 2023 (173,311) (7,947) (181,258)
Depreciation charge for the period (4,994) (339) (5,333)
Currency translation adjustments – (122) (122)
June 30, 2023 (178,305) (8,408) (186,713)
Net book value June 30, 2023 26,948 1,947 28,895
USD Thousands FPSO Other Total
Cost
January 1, 2022 206,173 10,163 216,336
Additions – 151 151
Disposals – (44) (44)
Currency translation adjustments (1,320) (491) (1,811)
December 31, 2022 204,853 9,779 214,632
Accumulated depreciation
January 1, 2022 (162,524) (7,449) (169,973)
Depreciation charge for the period (10,787) (891) (11,678)
Disposals – 36 36
Currency translation adjustments – 357 357
December 31, 2022 (173,311) (7,947) (181,258)
Net book value December 31, 2022 31,542 1,832 33,374
The FPSO located on the Bertam field, Malaysia, is being depreciated on a unit of production basis to August 2025, being the 
original Bertam field production sharing contract (PSC) expiry date, before PSC extension to 2035. The depreciation charge is 
included in the depreciation of other assets line in the statement of operations.
For office equipment and other assets, the depreciation charge for the year is based on cost and an estimated useful life of 3 to 
5 years. The depreciation charge is included within the general, administration and depreciation expenses in the Statement of 
Operations.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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

16
10. OTHER NON-CURRENT ASSETS
USD Thousands June 30, 2023 December 31, 2022
Long-term receivables  28,282    28,154
Financial assets  14,042    12,971
 42,324     41,125    
Long-term receivables represent cash payments made to an asset retirement obligation fund and financial assets include 
secured amounts of USD 7.7 million transferred for the future asset retirement obligation, in respect of the Bertam field, 
Malaysia. In 2023, an amount of USD 1.8 million (2022: USD 1.9 million) was paid into the asset retirement obligation fund 
which is held in local currency. (Also see Note 17.)
11. INVENTORIES
USD Thousands June 30, 2023 December 31, 2022
Hydrocarbon stocks  19,513     8,988    
Well supplies and operational spares  9,092     6,970    
 28,605     15,958    
12. TRADE AND OTHER RECEIVABLES
USD Thousands June 30, 2023 December 31, 2022
Trade receivables  74,750     112,696    
Underlift  5,126     599    
Joint operations debtors  1,693     982    
Prepaid expenses and accrued income  19,209     6,585    
Other  2,849     2,747    
 103,627     123,609    
13. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include only cash at hand or held in bank accounts. As at June 30, 2023, an amount of USD 5.2 million 
is restricted. 
14. SHARE CAPITAL
The Corporation’s issued common share capital is as follows:
Number of shares
Balance at January 1, 2022 155,198,105
Cancellation following the Substantial Issuer Bid (8,258,064)
Cancellation of repurchased common shares (10,112,042)
Balance at December 31, 2022 136,827,999
Cancellation of repurchased common shares (6,330,914)
Balance at June 30, 2023 130,497,085
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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

17
The common shares of IPC trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange. 
As at January 1, 2022, IPC had a total of 155,198,105 common shares issued and outstanding, of which IPC held 1,160,651
common shares in treasury. All common shares held in treasury as at January 1, 2022 were cancelled during January 2022.
During 2022, under the normal course issuer bid/share repurchase program announced in December 2021 and renewed in
December 2022 (NCIB), IPC purchased and cancelled an aggregate of 8,951,391 common shares.
During Q2 2022, IPC commenced an offer to repurchase common shares under the substantial issuer bid (SIB). Under the SIB,
IPC purchased and cancelled an aggregate of 8,258,064 common shares.
As at December 31, 2022, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in
treasury.
As at June 30, 2023, following the cancellation during the first six months of 2023 of a further 6,330,914 common shares 
repurchased under the NCIB, IPC had a total of 130,497,085 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, do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares and do not impact the earnings per share calculations.
15. EARNINGS PER SHARE
Basic earnings per share are based on net result attributable to the common shareholders and is calculated based upon the 
weighted-average number of common shares outstanding during the periods presented.
Three months ended June 30 Six months ended June 30
2023 2022 2023 2022
Net result attributable to shareholders of the Parent Company, USD 32,016,905 105,195,075 71,574,459 186,001,771
Weighted average number of shares for the period 132,052,470  150,966,013  134,396,105 153,035,036
Earnings per share, USD 0.24 0.70 0.53 1.22 
Weighted average diluted number of shares for the period 134,600,024  154,330,367 136,943,660  156,399,389 
Earnings per share fully diluted, USD 0.24  0.68 0.52 1.19
16. FINANCIAL LIABILITIES
USD Thousands June 30, 2023 December 31, 2022
Bank loans 10,629 12,142
Bonds 300,000 300,000
Capitalized financing fees (4,001) (4,560)
306,628 307,582
As at January 2022, the Group had a reserve-based lending (RBL) credit facility of USD 140 million in connection with its oil and
gas assets in France and Malaysia and a RBL credit facility of CAD 300 million in connection with its oil and gas assets in Canada. 
In February 2022, IPC completed the issuance of USD 300 million of Bonds, which mature in February 2027 and have a fixed
coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group used a portion of the
proceeds of the Bonds to fully repay the outstanding RBL credit facilities, which were then cancelled. At the same time, the Group
entered into a revolving credit facility of CAD 75 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In Q1 2023, the Group increased the Canadian RCF to CAD 150 million and extended the maturity to May 2025. No cash amounts
were drawn under the Canadian RCF as at June 30, 2023.
The Bond repayment obligations as at June 30, 2023, are classified as non-current as there are no mandatory repayments within 
the next twelve months.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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

18
As at June 30, 2023, IPC had a EUR 13 million unsecured credit facility in France (the “France Facility“), with maturity in May 
2026. IPC commenced quarterly repayments of the French Facility in August 2022. The amount remaining outstanding
under the France Facility as at June 30, 2023 was USD 11 million (EUR 10 million).
An amount of USD 3.5 million (EUR 3.2 million) drawn under the France Facility as at June 30, 2023 is classified as current
representing the repayment planned within the next twelve months.
The Group is in compliance with the covenants of the Bonds and its financing facilities as at June 30, 2023.
17. PROVISIONS
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2023 206,249 3,404 306 1,478 211,437
Acquisition of Cor4 - See Note 8 29,885 – – – 29,885
Additions – – – 338 338
Unwinding of asset retirement obligation discount 6,542 – – – 6,542
Payments (4,371) (557) – (307) (5,235)
Other 1 (1,277) – – – (1,277)
Reclassification 2 1,781 – – – 1,781
Currency translation adjustments 3,601 (170) – 15 3,446
June 30, 2023 242,410 2,677 306 1,524 246,917
Non-current 235,885 1,606 306 1,524 239,321
Current 6,525 1,071 – – 7,596
Total 242,410 2,677 306 1,524 246,917
1 Includes accelerated decommissioning activities funded by a non cash site rehabilitation program.
2 The reclassification of the asset retirement obligation related to the 2023 payment to the asset retirement obligation fund in respect of the Bertam 
asset, Malaysia (see Note 10).
USD Thousands
Asset 
retirement 
obligation
Farm-in 
obligation
Pension 
obligation Other Total
January 1, 2022 196,362 4,199 4,448 1,357 206,366
Additions – – 542 1,034 1,576
Unwinding of asset retirement obligation discount 10,758 – – – 10,758
Changes in estimates 11,375 567 (3,778) – 8,164
Payments (5,809) (1,153) (718) (865) (8,545)
Reclassification 1 1,909 – – – 1,909
Currency translation adjustments (8,346) (209) (188) (48) (8,791)
December 31, 2022 206,249 3,404 306 1,478 211,437
Non-current 199,335 2,270 306 1,478 203,389
Current 6,914 1,134 – – 8,048
Total 206,249 3,404 306 1,478 211,437
1 The reclassification of the asset retirement obligation related to the 2022 payment to the asset retirement obligation fund in respect of the Bertam 
asset, Malaysia (see Note 10).
The farm-in obligation relates to future payments for historic costs on Block PM307 in Malaysia payable on reaching certain Bertam 
field production milestones. 
In calculating the present value of the asset retirement obligation provision, a blended rate of 6% (2022: 6%) per annum was used, 
based on a credit risk adjusted rate.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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

19
18. TRADE AND OTHER PAYABLES
USD Thousands June 30, 2023 December 31, 2022
Trade payables  17,909     20,547    
Joint operations creditors  15,573     14,348    
Accrued expenses  87,009     78,206    
Other  4,059     5,625    
 124,550     118,726    
19. FINANCIAL ASSETS AND LIABILITIES
Financial assets and liabilities by category
The accounting policies for financial instruments have been applied to the line items below:
June 30, 2023
USD Thousands
Total
Financial assets 
at amortized 
cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Other assets1 42,324 42,324 – –
Derivative instruments 12,646 – – 12,646
Joint operation debtors 1,693 1,693 – –
Other current receivables2 85,077 79,951 5,126 –
Cash and cash equivalents 374,177 374,177 – –
Financial assets 515,917 498,145 5,126 12,646
1 See Note 10
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
June 30, 2023
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 303,116 303,116 – –
Current financial liabilities 3,512 3,512 – –
Derivative instruments 3,434 – – 3,434
Joint operation creditors 15,573 15,573 – –
Other current liabilities 111,831 111,831 – –
Financial liabilities 437,466 434,032 – 3,434
December 31, 2022
USD Thousands
Total Financial assets 
at amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives used 
for hedging
Other assets1 41,125 41,125 – –
Derivative instruments 11,741 – – 11,741
Joint operation debtors 982 982 – –
Other current receivables2 116,060 115,461 599 –
Cash and cash equivalents 487,240 487,240 – –
Financial assets 657,148 644,808 599 11,741
1 See Note 10
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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

20
December 31, 2022
USD Thousands
Total
Financial 
liabilities at 
amortized cost
Fair value 
recognized in 
profit or loss 
(FVTPL)
Derivatives 
used for 
hedging
Non-current financial liabilities 304,151 304,151 – –
Current financial liabilities 3,431 3,431 – –
Derivative instruments 1,155 – – 1,155
Joint operation creditors 14,348 14,348 – –
Other current liabilities 122,171 122,171 – –
Financial liabilities 445,256 444,101 – 1,155
The carrying amount of the Group’s financial assets approximate their fair values at the balance sheet dates.
 For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
  – Level 1: based on quoted prices in active markets;
  – Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
  – Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
June 30, 2023
USD Thousands Level 1 Level 2 Level 3
Other current receivables 5,126 – –
Derivative instruments – current – 9,502 –
Derivative instruments – non-current – – 3,144
Financial assets 5,126 9,502 3,144
Derivative instruments – current – 3,033 –
Derivative instruments – non-current – 401 –
Financial liabilities – 3,434 –
December 31, 2022
USD Thousands Level 1 Level 2 Level 3
Other current receivables 599 – –
Derivative instruments – current – 11,741 –
Financial assets 599 11,741 –
Derivative instruments – current – 1,155 –
Financial liabilities – 1,155 –
The Group had gas price sale financial hedges outstanding as at June 30, 2023, which are summarized as follows:
Period Volume (Gigajoules (GJ) per day) Type Average Pricing 
July 1, 2023 – October 31, 2023 35,0001 AECO Swap CAD 3.95/GJ 
1  Equivalent to 33,700 Mcf per day at CAD 4.10/Mcf.
The Group had oil price sale financial hedges outstanding as at June 30, 2023 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
July 1, 2023 - December 31, 2023 12,000 WCS/ARV Differential USD -10.08/bbl
January 1, 2024 - December 31, 2024 8,500 WCS/WTI Differential USD -13.91/bbl
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED

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

21
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2023 and 2022, UNAUDITED
The Group had condensate financial hedges outstanding as at June 30, 2023 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
October 31, 2023 – March 31, 2024 3,000 C5/WTI Differential USD -1.60/bbl 
The Group had electricity financial hedges outstanding as at June 30, 2023 which are summarized as follows:
Period Volume (MW) Type Pricing 
July 1, 2023 –  July 31, 2023 5 AESO CAD 72.95/MWh 
October 1, 2025 - September 1, 2040 3 AESO CAD 75.00/MWh
In October 2022, IPC entered into currency hedge swaps for 2023 to buy CAD 15 million per month, sell USD at an average
exchange rate of 1.3619 and to buy EUR 3 million per month, sell USD at an average exchange rate of 1.0000. In June 2023, IPC 
entered into currency hedge swaps for 2023 to buy MYR 13 million per month, sell USD at an average exchange rate of 4.5. This is to 
partially fund operational expenditures in those currencies in Canada, France and Malaysia respectively.
All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
20. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In Canada, an oil pipeline from the Onion Lake Thermal field to a gathering system has been built by a third party for the exclusive 
use of IPC. The initial investment in the pipeline was met by the pipeline owner and is to be recovered through an agreed tariff 
charged to IPC. IPC has committed to a firm transportation service for 15 years from commencement of service in April 2022, with 
total remaining tariffs committed as shown in the table below:
2023 2024 2025 2026 2027 Thereafter
Transportation service (MCAD) 13.8 28.0 28.4 29.0 28.2 275.2
In Malaysia, IPC has an obligation to make payments towards historic costs on Block PM307 payable on the Bertam field for every 
1 MMboe gross that the field produces above 10 MMboe gross. The estimated liability based on current 2P reserves and which is 
capped at cumulative production of 27.5 MMboe gross, has been provided for in the Group’s Balance Sheet (see Note 17).  
21. RELATED PARTIES
During Q2 2023, Lundin Foundation has charged the Group USD 182 thousand in respect of sustainability advisory services provided 
to the Group.
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.
22. SUBSEQUENT EVENTS
In July 2023, the Group also entered into the following oil price sale and foreign currrency financial hedges in Canada:
Period Volume (barrels per day) Type Average Pricing 
January 1, 2024 - December 31, 2024 3,300 WCS/WTI Differential USD -14.37/bbl
Period Total Amount Type Average CAD/USD Rate
August 2023 - March 2025 Buy MCAD 466 (sell USD) Forward swap 1.31
No other events have occurred since June 30, 2023, that are expected to have a substantial effect on this report.

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

Corporate Office
International Petroleum Corp
Suite 2000
885 West Georgia Street
Vancouver, BC
V6C 3E8, Canada
Tel: +1 604 689 7842
E-mail: info@international-petroleum.com
Web: international-petroleum.com□

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

Q2
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three and six months ended June 30, 2023

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
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 International Financial Reporting 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 21.
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 26.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada (other than the assets acquired 
in the Cor4 acquisition) are effective as of December 31, 2022, 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, 2022, price forecasts. 
Reserve estimates and estimates of future net revenue in respect of IPC’s oil and gas assets acquired in the Cor4 acquisition are effective as of December 31, 2022, 
and have been audited by GLJ Ltd. (GLJ), an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s 
December 31, 2022, 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, 2022, 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, 2022, 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  8
FINANCIAL REVIEW  11
• Financial Results 11
• Capital Expenditure 19
• Financial Position and Liquidity  20
• Non-IFRS Measures  21
• Off-Balance Sheet Arrangements  23
• Outstanding Share Data  23
• Contractual Obligations and Commitments  23
• Critical Accounting Policies and Estimates 24
• Transactions with Related Parties  24
• Financial Risk Management  24
RISK AND UNCERTAINTIES  25
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING  26
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION  26
RESERVES AND RESOURCES ADVISORY  28
OTHER SUPPLEMENTARY INFORMATION  30
2

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
INTRODUCTION
This management’s discussion and analysis (“MD&A”) for International Petroleum Corporation (“IPC” or the “Corporation” 
and, together with its subsidiaries, the “Group”) is dated August 1, 2023 and is intended to provide an overview of the Group’s 
operations, financial performance and current and future business opportunities. This MD&A should be read in conjunction with 
IPC’s unaudited interim condensed consolidated financial statements and accompanying notes for the three and six months ended 
June 30, 2023 (“Financial Statements”).
Group Overview
The Group is in the business of exploring for, developing and producing oil and gas. IPC holds a portfolio of oil and gas production 
assets and development projects in Canada, Malaysia and France with exposure to growth opportunities. 
The Corporation’s common shares are listed on the Toronto Stock Exchange in Canada and the Nasdaq Stockholm Exchange in 
Sweden. The Corporation is incorporated and domiciled in British Columbia, Canada, under the Business Corporations Act. The 
address of its registered office is Suite 2600, 595 Burrard Street, P .O. Box 49314, Vancouver, BC V7X 1L3, Canada and its business 
address is Suite 2000, 885 West Georgia Street, Vancouver, BC V6C 3E8, Canada.
Basis of Preparation
The MD&A and the Financial Statements have been prepared in accordance with International Financial Reporting 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:
June 30, 2023 June 30, 2022 December 31, 2022
Average Period end Average Period end Average Year end
1 EUR equals USD 1.0811 1.0866 1.0940 1.0387 1.0539 1.0666
1 USD equals CAD 1.3477 1.3266 1.2712 1.2925 1.3015 1.3538
1 USD equals MYR 4.4564 4.6675 4.2715 4.4075 4.3995 4.4050
              
IPC completed the acquisition of Cor4 Oil Corp. (“Cor4”) on March 3, 2023. In accordance with IFRS, the Financial Statements 
have been prepared on that basis, with revenues and expenses related to the assets acquired in the Cor4 acquisition included in 
the Financial Statements from March 3, 2023. See also “Cor4 Acquisition” below. Certain historical and forecast operational and 
financial information included in the MD&A, including production, reserves, operating costs, OCF , FCF and EBITDA related to the 
assets acquired in the Cor4 acquisition, are reported based on the effective date of the Cor4 acquisition of January 1, 2023. See 
also “Operations Overview – Production” and “Non-IFRS Measures” below.
3

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
HIGHLIGHTS
Q2 2023 Business Highlights
• Strong quarterly average net production of approximately 51,800 barrels of oil equivalent (boe) per day (boepd) for the second 
quarter of 2023 (49% heavy crude oil, 18% light and medium crude oil and 33% natural gas).(1) 
• Blackrod Phase 1 engineering, procurement and construction (EPC) contract for the Central Processing Facility (CPF) signed in 
Canada.
• Successfully integrated the assets acquired in the Cor4 acquisition in Canada.(1)(2) 
• 1.57 million common shares purchased and cancelled during Q2 2023 under IPC’s normal course issuer bid (NCIB).
• Published IPC’s fourth annual Sustainability Report (2022) and first standalone TCFD Report.
 
Q2 2023 Financial Highlights
• Operating costs per boe of USD 17.0 for Q2 2023.(1)(3)
• Operating cash flow (OCF) generation for Q2 2023 amounted to MUSD 84. (1)(3)
• Capital and decommissioning expenditures of MUSD 62 for Q2 2023. (1)
• Free cash flow (FCF) generation for Q2 2023 amounted to MUSD 16 (MUSD 65 pre Blackrod funding). (1)(3)
• Net cash of MUSD 64 as at June 30, 2023. (3)
• Net result of MUSD 32 for Q2 2023.
Reserves and Resources
• Total 2P reserves as at December 31, 2022 of 487 million boe (MMboe), with a reserves life index (RLI) of 27 years. (1)(2)
• Contingent resources (best estimate, unrisked) as at December 31, 2022 of 1,162 MMboe.(1)(2)
2023 Annual Guidance
• Full year 2023 average net production forecast expected to exceed the upper end of 48,000 to 50,000 boepd guidance 
range.(1)
• Full year 2023 operating costs guidance forecast remains unchanged at USD 17.5 to 18.0 per boe. (1)(3)
• Full year 2023 OCF guidance tightened to between MUSD 320 to 390 (assuming Brent USD 75 to 90 per barrel for the 
remainder of 2023) from previous guidance of MUSD 250 to 495 (assuming Brent USD 70 to 100 per barrel).
(1)(3)
• Full year 2023 capital and decommissioning expenditures guidance forecast unchanged at MUSD 365, including MUSD 287 
relating to Phase 1 of the Blackrod project.
(1)
• Full year 2023 FCF forecast range tightened to between MUSD -65 to 5 (assuming Brent USD 75 to 90 per barrel for the 
remainder of 2023) from previous guidance of MUSD -145 to 105 (assuming Brent USD 70 to 100 per barrel), after taking into 
account MUSD 287 of proposed 2023 Blackrod capital expenditures. (1)(3)(4)
Three months ended June 30 Six months ended June 30
USD Thousands 2023 2022 2023 2022
Revenue 205,564 315,540 398,080 575,322
Gross profit 52,747 161,709 117,130 280,809
Net result 32,025 105,217 71,588 186,039
Operating cash flow(3) 84,372 192,515 160,272 337,625
Free cash flow(3) 16,415 151,792 32,674 248,273
EBITDA(3) 85,201 194,038 161,280 339,501
Net Cash(3) 63,548 14,382 63,548 14,382
4

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
OPERATIONS REVIEW 
Business Overview
The pull back that we saw in oil and gas prices during the first quarter of 2023 stabilised during the second quarter with Brent 
prices averaging USD 78 per barrel compared with just over USD 80 per barrel during the first quarter. Demand concerns continue 
to weigh on oil markets, as rising interest rates aimed at taming high inflation, raise recessionary fears. The surprise production 
cuts announced by OPEC+ in early April were followed up with additional ‘voluntary cuts’ implemented by Saudi Arabia through 
July and August, a fourth pre-emptive move by the group, aimed at ensuring recent oil price weakness is not sustained. Inventory 
levels have moved back below the five-year average levels and market observers expect a deficit in the oil market for the 
remainder of 2023. Strategic Petroleum Reserve (SPR) releases in the US have come to an end and up to 12 million barrels are 
expected to be repurchased to begin refilling the SPR by the end of the year. The physical market certainly seems tighter than that 
priced in by the financial markets and many commentators believe oil prices will increase from the recent market trading range. 
We saw Brent prices trade in July occasionally over the USD 80 per barrel mark which had not been the case since April.
The second quarter 2023 West Texas Intermediate (WTI) to Western Canadian Select (WCS) crude price differentials averaged 
around USD 15 per barrel, USD 10 per barrel tighter than first quarter levels and USD 5 per barrel tighter than our base case 2023 
market guidance. Those market factors that have driven differentials wider such as the SPR releases, higher natural gas prices and 
refinery outages have now turned to provide more favourable tailwinds to the WTI/WCS differentials going forward. In addition, the 
expansion of the Trans Mountain pipeline (590,000 barrels per day of extra capacity linking Edmonton to the port of Vancouver) due 
in service in Q1 2024, as well as a reduction in Mexican heavy oil exports to the US (due to domestic refinery capacity increases by 
more than 200,000 barrels per day) is expected to provide stronger support to WTI/WCS differentials going forward. Current WTI/
WCS differentials have tightened to less than USD 15 per barrel for the remainder of 2023 and the whole of 2024 as a result of 
these favourable market developments. IPC has taken the opportunity to lock in a WTI/WCS differential of approximately USD 14 
per barrel for close to 50% of our forecast 2024 Canadian WCS forecast production volumes. Leveraging on the traditional lower 
costs for condensate in the summer season, we also locked in approximately 50%, or 3,000 barrels per day, of our Q3 2023 and 
Q1 2024 average daily condensate purchase forecast at WTI minus USD 1.60  per barrel.
Gas market prices remained below our 2023 base case price guidance of CAD 3.50 per Mcf during the second quarter. IPC’s 
average realised gas price was CAD 2.44 per Mcf during the quarter, compared with CAD 3.60 per Mcf during the first quarter of 
2023. The recent weakness seen in North American gas prices was to a large extent driven by a much milder winter in Europe and 
the resulting reduced demand for US LNG. IPC was partially protected by AECO gas price hedges that were put in place when gas 
prices were much stronger in late 2022: 33.7 MMcf per day at CAD 4.10 per Mcf from April to October 2023, which represents 
approximately 50% of our net long exposure.
Second Quarter 2023 Highlights and Full Year 2023 Guidance
During the second quarter of 2023, our assets delivered average net production of 51,800 boepd, above our high-end guidance 
for the second quarter in succession. This was made possible by the very high uptime performance across all our assets as 
well as the production contribution from our recent Cor4 acquisition in Canada and our successful four well drilling program in 
France. Given the very strong first half performance averaging around 52,000 boepd, full year 2023 average net production is now 
expected to exceed the upper end of the guidance range of 48,000 to 50,000 boepd.
(1)
Our operating costs per boe for the second quarter of 2023 were USD 17.0, in line with our latest guidance. Full year 2023 
operating costs per boe guidance of USD 17.5 to 18.0 per boe remains unchanged.
(1)(3)
Operating cash flow (OCF) generation for the second quarter of 2023 was USD 84 million, ahead of guidance as a result of 
the strong production performance and tighter WCS/WTI differentials. Full year 2023 OCF guidance of USD 250 to 495 million 
(assuming Brent USD 70 to 100 per barrel) is tightened to USD 320 to 390 million (assuming Brent USD 75 to 90 per barrel for the 
remainder of 2023).
(1)(3)
Full year 2023 capital and decommissioning expenditure forecast of USD 365 million is unchanged.(1)
Free cash flow (FCF) generation was USD 16 million (USD 65 million pre Blackrod funding) during the second quarter of 2023. Full 
year 2023 FCF guidance of USD -145 to 105 million (assumed Brent USD 70 to 100 per barrel) is tightened to USD -65 to 5 million 
(assuming Brent USD 75 to 90 per barrel for the remainder of 2023).
(1)(3)(4)
IPC’s transformational growth program is estimated to generate FCF post growth investment of between USD 2.6 and 4.4 billion 
over the next ten years assuming average Brent oil prices between USD 75 to 95 per barrel. This represents more than 2 to 3 
times IPC’s current market capitalisation.
(1)(3)(4)
During the second quarter of 2023, IPC’s net cash position of USD 67 million was reduced to USD 64 million, largely driven by 
the funding of USD 14 million for the continuing share repurchase program (NCIB) and other working capital movements.
(3) Gross 
cash on the balance sheet as at June 30, 2023 amounts to USD 374 million providing a significant war chest to pursue our three 
strategic pillars of returning value to stakeholders, pursuing value adding M&A and focusing on organic growth. Furthermore, IPC’s 
CAD 150 million Canadian Revolving Credit Facility (RCF) remains undrawn. 
5

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Phase 1 Blackrod Project
Following the successful completion of FEED studies and the continued strong production performance from well pair three 
during 2022, IPC took the decision in Q1 2023 to advance the development of Phase 1 of the Blackrod project. Development 
capital expenditure to first oil is estimated at approximately USD 850 million (including inflation and contingencies). First oil of the 
Phase 1 development is estimated to be in late 2026, with forecast production of 30,000 bopd by 2028. The breakeven oil price 
estimated by IPC assuming a 10% discount rate is a WTI price of approximately USD 59 per barrel. Using the December 31, 2022 
price forecasts of our independent qualified reserves evaluator, Sproule Associates Limited (Sproule), the net present value as at 
that date, at a 10% discount rate (after tax), of Phase 1 of the Blackrod project is USD 807 million. IPC intends to fund the Phase 1 
development with cash on hand and forecast FCF generated by our operations.
(1)(2)
During the second quarter, the Phase 1 development activities have progressed according to plan. The engineering, procurement 
and construction (EPC) contract for the major Phase 1 central processing facility was signed with cost levels and schedule in line 
with expectation. This contract provides a high degree of certainty for the largely fixed price element of the Phase 1 development 
capital expenditure which represents close to 65% of the overall Phase 1 capital expenditure budget to first oil. In addition, IPC has 
decided to lock in approximately 65% of the CAD/USD exposure through a combination of hedging and contractual arrangements 
to give greater certainty to the USD funding requirement for the Phase 1 project costs. Following these actions, more than 85% of 
the overall Phase 1 contingency (USD 110 million) remains available, a comfortable position to be in. 
However, we believe it is prudent to retain the total Phase 1 capital expenditure estimate to first oil of USD 850 million given the 
early stages in the project’s execution.
M&A
During Q2 2023, IPC successfully integrated the acquired Cor4 assets into the Group following completion of the acquisition in 
March 2023. Four wells were successfully drilled and brought on production from the Ellerslie fairway since the beginning of the 
year and we plan to drill another two wells on this exciting play in 2023.
(1)(2)
2023 Capital Allocation Framework
Normal Course Issuer Bid
In Q4 2022, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 9.3 million common shares 
over the twelve-month period to early December 2023. By the end of June 2023, IPC purchased and cancelled 7.1 million common 
shares under the NCIB. The average price of common shares purchased under the renewed NCIB during the period of December 
2022 to June 2023 was SEK 101 / CAD 13.00 per share.
As at June 30, 2023, IPC had a total of 130,497,085 common shares issued and outstanding, with no common shares held in 
treasury.
2023 Capital Allocation Plans
IPC’s capital allocation framework consists of distributing to shareholders a minimum of 40% of the FCF generated by the 
business, provided that IPC’s net debt to EBITDA ratio is at or below 1 time.
(3) These shareholder distributions are planned to be 
implemented by continued share repurchases under the NCIB as well as the consideration by IPC of other forms of shareholder 
distributions, subject to further applicable regulatory and corporate approvals.
Despite the higher level of capital investment, and notwithstanding the capital allocation framework described above, IPC plans to 
continue to purchase and cancel common shares under the NCIB to the remaining limit as at June 30, 2023 of 2.2 million common 
shares by the end of November 2023, resulting in the anticipated cancellation of 7% of shares outstanding as of December 2022. 
We believe a combination of materially growing our 2P reserves, production and asset value whilst reducing our share count is a 
winning combination for shareholders.
Environmental, Social and Governance (ESG) Performance
IPC is committed to the continued advancement of our ESG practices in our sustainability focus areas. The Group’s six 
sustainability priorities are:
• Ethics & Integrity
• Rewarding Workplace
• Health & Safety
• Community Engagement
• Climate Action
• Environmental Stewardship
As part of our commitment to operational excellence, our objective is to reduce risk and eliminate hazards to prevent the 
occurrence of accidents, ill health and environmental damage, as these are essential to the success of our operations. During the 
second quarter of 2023, IPC recorded no material safety or environmental incidents.
6

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
With respect to climate action, IPC has made notable progress over the past years. Our operational emission reduction efforts 
have resulted in a reduction of greater than 125,000 tonnes of CO2e emissions since announcing IPC’s climate strategy in 2020. 
IPC also signed its first virtual green power purchase agreement in 2022, contributing to a greater share of green energy in the 
Alberta electricity grid. In addition, IPC expanded carbon compensation efforts by offsetting a substantial share of the Group’s 2022 
CO
2e emissions, offsetting a total of 330,000 tonnes of CO2e for the year 2022. These initiatives put IPC on track to achieve a 50% 
reduction in our net emissions intensity by 2025, and the company announced this year at the 2023 Capital Markets Day (CMD) a 
commitment to extend the reduced net emissions intensity level through 2027.
Sustainability Reporting and Climate disclosures
Alongside the publication of this second quarter 2023 financial report, IPC releases its fourth annual Sustainability Report and its 
first standalone TCFD Report. The Sustainability Report provides details on IPC’s approach to sustainability, highlighting specific 
initiatives, and measurable goals and targets related to the key focus areas set by the Group. The TCFD Report aligns with the 
recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) and demonstrates our commitment to 
addressing climate-related risks and opportunities to our business.
The Sustainability Report and the TCFD Report, including additional information on IPC’s efforts and performance across its 
sustainability priorities, are available on our website at www.international-petroleum.com.
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, 2022 (AIF) available on IPC’s website at www.international-
petroleum.com and under IPC’s profile on SEDAR+ at www.sedarplus.ca. IPC completed the acquisition of Cor4 on March 
3, 2023. The Financial Statements have been prepared on that basis, with revenues and expenses related to the assets 
acquired in the Cor4 acquisition included in the Financial Statements from March 3, 2023. Certain historical and forecast 
operational and financial information included in the MD&A, including production, reserves, operating costs, OCF , FCF 
and EBITDA related to the assets acquired in the Cor4 acquisition, are reported based on the effective date of the Cor4 
acquisition of January 1, 2023. 
 
(2) See ”Reserves and Resources Advisory” below. Further information with respect to IPC’s reserves, contingent resources 
and estimates of future net revenue, including assumptions relating to the calculation of NPV, are described in the AIF . 2P 
reserves as at December 31, 2022 of 487 MMboe includes 471 MMboe attributable to IPC’s oil and gas assets and 15.9 
MMboe attributable to the oil and gas assets acquired in the Cor4 acquisition. 
(3) Non-IFRS measure, see “Non-IFRS Measures” below. 
(4) Estimated FCF generation is based on IPC’s current business plans over the periods of 2023 to 2027 and 2028 to 2032, 
including net cash of USD 175 million as at December 31, 2022 less the Cor4 acquisition consideration of USD 62 million. 
Assumptions include average net production of approximately 50 Mboepd over the period of 2023 to 2027, average net 
production of approximately 65 Mboepd over the period of 2028 to 2032, average Brent oil prices of USD 75 to 95 per boe 
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 market capitalization is at close on July 
28, 2023 (USD 1,190 million based on 95.92 SEK/share, 130.5 million IPC shares outstanding and exchange rate of 10.55 
SEK/USD. 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. See “Forward-Looking Statements” below.
7

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Operations Overview 
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 487 MMboe as at December 31, 2022, as certified by independent 
third party reserve auditors. The proved plus probable reserve life index (RLI) as at December 31, 2022, is approximately 27 years. 
Best estimate contingent resources as at December 31, 2022, are 1,162 MMboe (unrisked). See “Reserves and Resources 
Advisory” below.
With the acquisition of the Cor4 assets in the Suffield area and the growth investment associated with the sanction of the 
Blackrod Phase 1 development in 2023, IPC has set a reduced base business capital budget for the year. In Canada, the Blackrod 
Phase 1 development is progressing in line with schedule and budget. The major facility EPC contract has been signed, bringing 
a higher degree of cost certainty on a significant portion of the Phase 1 project. In the Suffield area, four out of the six planned 
Ellerslie play wells have been drilled by end Q2 2023. In France, planned drilling operations have been successfully completed with 
all three Villeperdue West oil wells and the Merisier side-track well online and performing ahead of forecast. In Malaysia, evaluation 
of a potential next phase of field development is progressing in line with schedule. IPC remains focused on organic growth and 
continues to mature future development projects across all operated assets, with a significant portfolio of drilling and optimisation 
opportunities ready for sanction at the discretion of the Group.
Production
Average daily net production for the second quarter 2023 was above the high end of our CMD guidance range at 51,800 boepd. 
In Canada, strong performance and high production uptimes have been supplemented by the newly drilled Suffield Ellerslie 
production wells which continue to exceed expectations. In addition, in Malaysia, the Bertam field continued to deliver excellent 
results with production well rate optimisation activity and high facility uptime during the quarter. In France, all four planned 2023 
production wells are online and delivering ahead of forecast.  
With exceptional operational performance during the first six months of 2023 and the production benefit from the 2023 capital 
expenditure investments in Canada and France, full year 2023 average net production is expected to exceed the upper end of the 
original CMD guidance of 48,000 to 50,000 boepd.
The production during Q2 2023 with comparatives is summarized below:
Production
in Mboepd
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2023 2022 2023 2022 2022
Crude oil
Canada – Northern Assets 15.1 15.6 15.5 15.2 15.6
Canada – Southern Assets1 11.7 8.5 12.2 8.5 8.7
Malaysia 4.8 5.9 4.9 5.0 5.3
France 2.8 2.8 2.7 2.8 2.7
Total crude oil production 34.4 32.8 35.3 31.5 32.3
Gas
Canada – Northern Assets 0.4 0.1 0.4 0.1 0.1
Canada – Southern Assets 17.0 16.5 16.6 16.0 16.2
Total gas production 17.4 16.6 17.0 16.1 16.3
Total production 51.8 49.4 52.3 47.6 48.6
Quantity in MMboe 4.72 4.49 9.47 8.61 17.74
1 Includes production from the Cor4 assets in the Suffield area from January 1, 2023. The acquisition of Cor4 was completed on March 3, 2023.
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
8

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
CANADA
Production
in Mboepd WI
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2023 2022 2023 2022 2022
- Oil Onion Lake Thermal 100% 12.9 12.8 13.1 12.3 12.7
- Oil Suffield Area1 100% 10.1 7.4 10.4 7.4 7.1
- Oil Ferguson 100% 1.6 1.1 1.8 1.1 1.6
- Oil Other 50-100% 2.2 2.8 2.4 2.9 2.9
- Gas1 ~100%2 17.4 16.6 17.0 16.1 16.3
Canada 44.2 40.7 44.7 39.8 40.6
1  Including the production contribution of the Cor4 acquisition from the effective date of January 1, 2023. The acquisition of Cor4 was completed 
on March 3, 2023.
2  On a well count basis
Production
Net production from IPC’s Canadian assets during Q2 2023 was ahead of guidance at 44,200 boepd. The Suffield area oil and gas 
producing assets continue to deliver above forecast, where base well rate optimisation has been supplemented by the newly 
drilled Suffield Ellerslie production wells which continue to exceed expectations. Stable operations and high production uptimes 
have continued at the Onion Lake Thermal asset in Q2 2023.
Organic Growth and Capital Projects
In Canada, the Blackrod Phase 1 development was sanctioned in Q1 2023. A reduced base business budget for the remainder of 
the assets in Canada has been set for 2023 with a focus on oil well drilling in the Suffield Ellerslie formation and the completion of 
the next production sustaining Pad L at Onion Lake Thermal.
As of the end of Q2 2023 at Blackrod, the Phase 1 development early ground works, detailed engineering, procurement of long 
lead items, and fabrication of facility modules has progressed in line with schedule and budget. The EPC contract for the major 
central processing facility (CPF) has been signed as planned with cost levels and schedule in line with expectation. This contract 
includes a significant fixed price element and provides a higher degree of spend certainty representing close to 65% of the Phase 
1 development capital expenditure.
At Suffield, four out of six of the planned Ellerslie play wells in 2023 have been drilled and brought online with encouraging initial 
results. 
At Onion Lake Thermal, the next sustaining production Pad L completions have progressed ahead of schedule with steam injection 
started up at the first two Pad L production wells in July. A period of steam injection optimisation and well conformance testing 
will be completed prior to first oil production from the Pad. First oil remains on track for Q4 2023.
MALAYSIA
Production
in Mboepd WI
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2023 2022 2023 2022 2022
Bertam 100% 4.8 5.9 4.9 5.0 5.3
Production
Strong performance in Q2 2023 from Bertam field on Block PM307 with average net production ahead of guidance at 4,800 boepd. 
Exceptional facility and well performance continued with facility uptimes registered in excess of 99%. 
Organic Growth and Capital Projects
In Malaysia, a limited capital budget was set for 2023 with our focus now on studying the remaining undeveloped potential of the 
Bertam field following the successful results from the latest development drilling campaign in the north east of the field.
9

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
FRANCE
Production
in Mboepd WI
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2023 2022 2023 2022 2022
France
- Paris Basin 100%1 2.5 2.5 2.3 2.5 2.4
- Aquitaine 50% 0.3 0.3 0.4 0.3 0.3
2.8 2.8 2.7 2.8 2.7
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q2 2023 was in line with the guidance at 2,800 boepd.
Organic Growth
In France, all three Villeperdue West oil wells and the planned Merisier side-track oil well have been drilled, completed and brought 
online with production performing ahead of forecast.  
IPC continues to mature future development projects in France, with focus towards the undeveloped resource base within the 
Paris Basin supported by the positive results following the 2023 development campaign.
10

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
FINANCIAL REVIEW 
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q2-23 Q1-23 Q4-22 Q3-22 Q2-22 Q1-22 Q4-21 Q3-21
Revenue 205,564 192,516 253,921 297,952 315,540 259,782 215,296 172,551
Gross profit 52,747 64,383 95,411 140,489 161,709 119,100 79,469 58,636
Net result 32,025 39,563 61,183 90,503 105,217 80,822 66,918 30,557
Earnings per share – USD 0.24 0.29 0.45 0.63 0.70 0.52 0.43 0.20
Earnings per share fully
diluted – USD 0.24 0.28 0.44 0.62 0.68 0.51 0.42 0.19
Operating cash flow1 84,372 75,900 113,668 171,654 192,515 145,110 110,687 91,365
Free cash flow1 16,415 16,259 65,288 116,681 151,792 96,479 86,960 76,607
EBITDA1 85,201 76,079 125,651 174,328 194,038 145,463 110,087 89,223
Net cash / (debt) at period end1 63,548 66,956 175,098 88,615 14,382 (42,367) (94,312) (161,199)
1  See definition on page 21 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands June 30, 2023 December 31, 2022
Non-current assets 1,201,668 1,041,051
Current assets 518,263 638,566
Total assets 1,719,931 1,679,617
Total non-current liabilities 598,798 564,381
Current liabilities 142,334 149,905
Total liabilities 741,132 714,286
Net assets 978,799 965,331
Working capital (including cash) 375,929 488,661
11

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
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 of the Suffield assets (including the Cor4 acquisition assets) and the Ferguson asset). This is 
consistent with the internal reporting provided to IPC management. The following tables present certain segment information.
Three months ended June 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 104,666 67,473 22,105 18,027 – 212,271
NGLs – 278 – – – 278
Gas 63 15,313 – – – 15,376
Net sales of oil and gas 104,729 83,064 22,105 18,027 – 227,925
Change in under/over lift position – – – 1,823 – 1,823
Royalties (14,964) (10,111) – (862) – (25,937)
Hedging settlement (1,271) 2,802 – – – 1,531
Other operating revenue – 1 – 221 – 222
Revenue 88,494 75,756 22,105 19,209 – 205,564
Operating costs (23,450) (41,699) (7,271) (7,867) – (80,287)
Cost of blending (35,005) (5,865) – – – (40,870)
Change in inventory position 802 (426) 4,747 (563) – 4,560
Depletion (9,222) (14,993) (5,551) (3,596) – (33,362)
Depreciation of other assets – – (2,436) – – (2,436)
Exploration and business
development costs – (3) – (9) (410) (422)
Gross profit/(loss) 21,619 12,770 11,594 7,174 (410) 52,747
Three months ended June 30, 2022
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 164,373 81,289 32,630 27,741 – 306,033
NGLs – 235 – – – 235
Gas 388 50,841 – – – 51,229
Net sales of oil and gas 164,761 132,365 32,630 27,741 – 357,497
Change in under/over lift position – – – 4,668 – 4,668
Royalties (20,740) (15,606) – (1,863) – (38,209)
Hedging settlement (177) (8,423) – – – (8,600)
Other operating revenue – – – 184 – 184
Revenue 143,844 108,336 32,630 30,730 – 315,540
Operating costs (29,438) (25,526) (6,822) (8,901) – (70,687)
Cost of blending (47,380) (10,259) – – – (57,639)
Change in inventory position 168 1,337 8,547 123 – 10,175
Depletion (8,466) (10,452) (9,713) (3,199) – (31,830)
Depreciation of other assets – – (3,021) – – (3,021)
Exploration and business
development costs 97 – – – (926) (829)
Gross profit/(loss) 58,825 63,436 21,621 18,753 (926) 161,709
12

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Six months ended June 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 200,495 119,375 39,776 33,158 – 392,804
NGLs – 468 – – – 468
Gas 157 35,702 – – – 35,859
Net sales of oil and gas 200,652 155,545 39,776 33,158 – 429,131
Change in under/over lift position – – – 4,493 – 4,493
Royalties (25,783) (17,957) – (2,336) – (46,076)
Hedging settlement (635) 10,750 – – – 10,115
Other operating revenue – 7 – 410 – 417
Revenue 174,234 148,345 39,776 35,725 – 398,080
Operating costs (48,483) (76,197) (15,447) (15,605) – (155,732)
Cost of blending (75,745) (12,942) – – – (88,687)
Change in inventory position 341 (387) 10,619 (278) – 10,295
Depletion1 (6,117) (15,575) (11,380) (6,729) – (39,801)
Depreciation of other assets – – (4,994) – – (4,994)
Exploration and business
development costs – (834) – (9) (1,188) (2,031)
Gross profit/(loss) 44,230 42,410 18,574 13,104 (1,188) 117,130
1  In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program.
Six months ended June 30, 2022
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Other Total
Crude oil 288,680 148,212 68,644 61,400 – 566,936
NGLs – 462 – – – 462
Gas 653 80,792 – – – 81,445
Net sales of oil and gas 289,333 229,466 68,644 61,400 – 648,843
Change in under/over lift position – – – (1,445) – (1,445)
Royalties (35,805) (24,529) – (3,387) – (63,721)
Hedging settlement (30) (8,826) – – – (8,856)
Other operating revenue – 101 – 400 – 501
Revenue 253,498 196,212 68,644 56,968 – 575,322
Operating costs (54,658) (52,743) (16,408) (18,339) – (142,148)
Cost of blending (80,318) (19,962) – – – (100,280)
Change in inventory position 1,491 942 10,683 612 – 13,728
Depletion (16,353) (20,424) (16,402) (6,603) – (59,782)
Depreciation of other assets – – (5,101) – – (5,101)
Exploration and business
development costs 97 – – – (1,027) (930)
Gross profit/(loss) 103,757 104,025 41,416 32,638 (1,027) 280,809
13

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Three and six months ended June 30, 2023, Review 
Revenue
Total revenue amounted to USD 205,564 thousand for Q2 2023, compared to USD 315,540 thousand for Q2 2022 and USD 
398,080 thousand for the first six months of 2023 compared to USD 575,322 thousand for the first six months of 2022 and is 
analyzed as follows:
USD Thousands 
Three months ended June 30 Six months ended June 30
2023 2022 2023 2022
Crude oil sales 212,271 306,033 392,804 566,936
Gas and NGL sales 15,654 51,464 36,327 81,907
Change in under/overlift position 1,823 4,668 4,493 (1,445)
Royalties (25,937) (38,209) (46,076) (63,721)
Hedging settlement 1,531 (8,600) 10,115 (8,856)
Other operating revenue 222 184 417 501
Total revenue 205,564 315,540 398,080 575,322
The main components of total revenue for the three and six months ended June 30, 2023, and June 30, 2022, respectively, are 
detailed below. 
Crude oil sales
Three months ended June 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 104,666 67,473 22,105 18,027 212,271
- Quantity sold in bbls 1,796,457 1,155,916 240,354 231,171 3,423,898
- Average price realized USD per bbl 58.26 58.37 91.97 77.98 62.00
Three months ended June 30, 2022
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 164,373 81,289 32,630 27,741 306,033
- Quantity sold in bbls 1,733,341 854,436 268,608 243,918 3,100,303
- Average price realized USD per bbl 94.83 95.14 121.48 113.73 98.71
Crude oil revenue was 31% lower in Q2 2023 compared to Q2 2022 mainly due to lower oil prices. Canadian - Southern Assets 
sales volumes are 35% higher in Q2 2023 compared to Q2 2022 as a result of the Cor4 acquistion in Q1 2023.
The Suffield area assets and Onion Lake crude oil in Canada are blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada. The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q2 2023, WTI averaged USD 73 per bbl compared to USD 109 per bbl for Q2 2022 and the 
average discount to WCS used in our pricing formula was USD 15 per bbl compared to USD 13 per bbl for Q2 2022.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia
during Q2 2023 and one cargo lifting in Q2 2022. Produced unsold oil barrels from Bertam at the end of Q2 2023 amounted to 
404,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 78 per bbl for 
Q2 2023 compared to USD 114 per bbl for the comparative period.
14

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Six months ended June 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 200,495 119,375 39,776 33,158 392,804
- Quantity sold in bbls 3,711,254 2,132,174 445,692 417,105 6,706,225
- Average price realized USD per bbl 54.02 55.99 89.25 79.50 58.57
Six months ended June 30, 2022
USD Thousands Canada –
Northern Assets
Canada –
 Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 288,680 148,212 68,644 61,400 566,936
- Quantity sold in bbls 3,312,105 1,704,153 558,901 595,241 6,170,400
- Average price realized USD per bbl 87.16 86.97 122.82 103.15 91.88
The Suffield area assets and Onion Lake crude oil in Canada are blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada. 
Crude oil revenue were lower by 31% during the first six months of 2023 compared to the first six months of 2022 mainly due to 
lower oil prices. Canadian - Southern Assets sales volumes are 25% higher in the first six months 2023 compared to the first six 
months of 2022 as a result of the Cor4 acquistion in Q1 2023.
The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. For the first six months of 2023, 
WTI averaged USD 75 per bbl compared to USD 102 per bbl for the comparative period and the average discount to WCS used in 
our pricing formula was USD 20 per bbl compared to USD 14 per bbl for the comparative period.
The realized sales price for Malaysia and France is based on Brent crude oil prices and the average market Brent crude oil price 
was USD 80 per bbl for the first six months of 2023 compared to USD 108 per bbl for the comparative period.
Gas and NGL sales
Three months ended – June 30, 2023
Canada –
Southern Assets
Canada –
 Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 15,591 63 15,654
- Quantity sold in Mcf 8,448,955 41,620 8,490,575
- Average price realized USD per Mcf 1.85 1.52 1.84
Three months ended – June 30, 2022
Canada –
Southern Assets
Canada –
 Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 51,076 388 51,464
- Quantity sold in Mcf 8,293,354 69,649 8,363,003
- Average price realized USD per Mcf 6.16 5.57 6.15
Gas and NGL sales revenue was 70% lower for Q2 2023 compared to Q2 2022 mainly due to the lower achieved gas price. IPC’s 
achieved gas price is based on AECO pricing plus a premium. For Q2 2023, IPC realized an average price of CAD 2.44 per Mcf 
compared to AECO average pricing of CAD 2.41 per Mcf. 
15

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Six months ended June 30, 2023
Canada –
Southern Assets
Canada –
 Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 36,170 157 36,327
- Quantity sold in Mcf 16,094,254 94,669 16,188,923
- Average price realized USD per Mcf 2.25 1.66 2.24
Six months ended June 30, 2022
Canada –
Southern Assets
Canada –
 Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 81,254 653 81,907
- Quantity sold in Mcf 15,964,279 135,838 16,100,117
- Average price realized USD per Mcf 5.09 4.80 5.09
Gas and NGL sales revenue was 56% lower for the first six months of 2023 compared to the first six months of 2022 mainly due 
to the lower achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For the first six months of 2023, IPC realized an average price 
of CAD 3.00 per Mcf compared to AECO average pricing of CAD 2.80 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. The oil and gas pricing contracts are not entered into for speculative purposes. 
The realized hedging settlement for the first six months of 2023 amounted to a gain of USD 10,115 thousand and consisted of 
a gain of USD 10,776 thousand on the gas contracts and a loss of USD 661 thousand on the oil contracts. Also see the Financial 
Position and Liquidity and the Financial Risk Management sections below.
Other operating revenue
Other operating revenue amounted to USD 222 thousand for Q2 2023 compared to USD 184 thousand for Q2 2022 and USD 417 
thousand for the first six months of 2023 compared to USD 501 thousand for the comparative period and mainly consists of tariff 
income and fees for strategic storage of inventory in France. 
Production costs
Production costs including inventory movements amounted to USD 116,597 thousand for Q2 2023 compared to USD 118,151 
thousand for Q2 2022 and USD 234,124 thousand for the first six months of 2023 compared to USD 228,700 thousand for the 
comparative period, and is analyzed as follows:
Three months ended June 30, 2023
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other3 Total
Operating costs1 41,699 23,450 11,366 7,867 (4,095) 80,287
USD/boe2 15.96 16.62 26.12 30.44 n/a 17.02
Cost of blending 5,865 35,005 – – – 40,870
Change in inventory position 426 (802) (4,747) 563 – (4,560)
Production costs 47,990 57,653 6,619 8,430 (4,095) 116,597
16

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Three months ended June 30, 2022
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other3 Total
Operating costs1 25,526 29,438 10,917 8,900 (4,095) 70,687
USD/boe2 11.28 20.55 20.24 34.55 n/a 15.74
Cost of blending 10,259 47,380 – – – 57,639
Change in inventory position (1,337) (168) (8,547) (123) – (10,175)
Production costs 34,448 76,650 2,370 8,777 (4,095) 118,151
Six months ended – June 30, 2023
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other3 Total
Operating costs1 76,197 48,483 23,592 15,605 (8,145) 155,732
USD/boe2 15.54 16.89 26.45 32.34 n/a 17.03
Cost of blending 12,942 75,745 – – – 88,687
Change in inventory position 387 (341) (10,619) 278 – (10,295)
Production costs 89,526 123,887 12,973 15,883 (8,145) 234,124
Six months ended – June 30, 2022
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other3 Total
Operating costs1 52,743 54,658 24,553 18,339 (8,145) 142,148
USD/boe2 11.94 19.72 26.95 35.66 n/a 16.50
Cost of blending 19,962 80,318 – – – 100,280
Change in inventory position (942) (1,491) (10,683) (612) – (13,728)
Production costs 71,763 133,485 13,870 17,727 (8,145) 228,700
1  See definition on page 21 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 includes Cor4 from 
January 1, 2023.
3  Included in the Malaysia operating costs is the lease cost for the FPSO Bertam which is owned by the Group. Other represents the FPSO Bertam
 lease fee self-to-self payment elimination. Netting the self-to-self elimination against the operating costs in Malaysia reduces the operating costs
 per boe for Malaysia to USD 16.71 and USD 12.65 for Q2 2023 and Q2 2022 respectively and USD 17.32 and USD 18.01 for the six months 
ended June 30, 2023, and June 30, 2022, respectively.
Operating costs
Operating costs amounted to USD 80,287 thousand for Q2 2023 compared to USD 70,687 thousand for Q2 2022 and USD 
155,732 thousand for the first six months of 2023 compared to USD 142,148 for the first six months of 2022. The increase in 
costs in Q2 2023 compared to Q2 2022 is due mainly to increased production and activity levels and higher electricity prices. 
Operating costs per boe amounted to USD 17.02 per boe in Q2 2023 in line with guidance for the quarter and compared with USD 
15.74 per boe in Q2 2022. The full year CMD guidance of USD 17.5 to 18 per boe remains unchanged. 
Cost of blending
For the Suffield area assets in Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. 
As a result of the blending, actual sales volumes are higher than produced barrels and the realized sales price of a blended barrel 
is higher than an unblended barrel. The majority of Onion Lake oil production is also blended and exported by pipeline since April 
2022 with the commissioning of a third party export pipeline from the Onion Lake field to the gathering system.
The cost of the diluent net of proceeds from the sale of surplus diluent amounted to USD 40,870 thousand for Q2 2023 compared 
to USD 57,639 thousand for Q2 2022 and USD 88,687 thousand for the first six months of 2023 compared to USD 100,280 for the 
comparative period. The decrease versus the comparative period is attributable to lower commodity pricing reflected in the cost of 
diluent. 
17

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Change in inventory position
The Bertam field in Malaysia is located offshore and production is lifted and sold from the FPSO Bertam when a cargo parcel size 
is reached. Accordingly, the timing of a lifting varies based on the inventory level on the FPSO facility and the change in inventory 
position varies, both positively and negatively, from period to period. Inventories are valued at the lower of cost including depletion, 
and market value, and the difference in the valuation between period ends is reflected in the change in inventory position in the 
statement of operations. At the end of Q2 2023, IPC had crude entitlement of 404,000 barrels of oil on the FPSO Bertam facility 
(crude produced but unsold). One crude cargo was lifted from Bertam in April 2023 with the next lifting in July 2023.
Depletion and decommissioning costs
The total depletion of oil and gas properties amounted to USD 33,362 thousand for Q2 2023 compared to USD 31,830 thousand 
for Q2 2022 and USD 39,801 thousand for the first six months of 2023 (including an adjustment for accelerated decommissioning 
activities amounting to USD 24,123 thousand) compared to USD 59,782 thousand for the first six months of 2022. The depletion 
charge is analyzed in the following tables:
Three months ended June 30, 2023
USD Thousands Canada –
Southern Assets
Canada –
 Northern Assets Malaysia France Total
Depletion cost in USD thousands 14,993 9,222 5,551 3,596 33,362
USD per boe2 5.74 6.53 12.76 13.92 7.07
Three months ended June 30, 2022
USD Thousands Canada –
Southern Assets
Canada –
 Northern Assets Malaysia France Total
Depletion cost in USD thousands 10,452 8,466 9,713 3,199 31,830
USD per boe2 4.62 5.91 18.01 12.42 7.09
Six months ended June 30, 2023
USD Thousands Canada –
Southern Assets
Canada –
 Northern Assets Malaysia France Total
Depletion cost in USD thousands1 27,267 18,548 11,380 6,729 63,924
USD per boe2 5.69 6.46 12.76 13.94 7.01
Six months ended June 30, 2022
USD Thousands Canada –
Southern Assets
Canada –
 Northern Assets Malaysia France Total
Depletion cost in USD thousands 20,424 16,353 16,402 6,603 59,782
USD per boe2 4.62 5.90 18.01 12.84 6.94
1  In Canada, excludes the adjustment for accelerated decommissioning activities.
2  USD/boe in the tables above is calculated by dividing the depletion cost by the production volume for each country for the period and includes 
Cor4 from January 1, 2023.
The depletion charge is derived by applying the depletion rate per boe to the volumes produced in the period by each field. The 
depletion rate in Malaysia has significantly decreased compared to the prior year following the extension to the Bertam field 
production sharing contract and consequent increase in field reserves announced at the end of 2022. In addition, the depletion rate 
in Canada - Southern Assets has increased compared to the prior year as a result of the Cor4 acquisition.
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 2,436 thousand for Q2 2023 compared to USD 3,021 thousand for Q2 
2022 and USD 4,994 thousand for the first six months of 2023 compared to USD 5,101 thousand for the first six months of 2022. 
This relates to the depreciation of the FPSO Bertam, which is being depreciated on a unit of production basis to August 2025, 
being the original Bertam field production sharing contract (PSC) expiry date, before PSC extension to 2035.
Exploration and business development costs
The total exploration and business developments costs amounted to USD 422 thousand for Q2 2023 and USD 2,031 thousand for 
the first six months of 2023. These costs included Cor4 acquisition related costs amounting to USD 831 thousand.
18

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
General, administrative and depreciation expenses
General, administrative and depreciation expenses amounted to USD 4,158 thousand for Q2 2023, compared to USD 3,743 
thousand for Q2 2022 and USD 8,352 thousand for the first six months of 2023 compared to USD 7,916 thousand for the first six 
months of 2022. 
Net financial items
Net financial items amounted to a charge of USD 6,955 thousand for Q2 2023, compared to a charge of USD 15,297 thousand for 
Q2 2022 and a charge of USD 11,970 thousand for the first six months of 2023 compared to a charge of USD 21,904 thousand for 
the first six months of 2022, and included a largely non-cash net foreign exchange loss of USD 2,347 thousand for the first
six months of 2023 compared to a net foreign exchange loss of USD 4,043 thousand for the first six months of 2022. The foreign 
exchange movements during the first six months of 2023 are mainly resulting from the revaluation of intra-group loan funding 
balances.
Excluding foreign exchange movements, the net financial items amounted to a charge of USD 5,464 thousand for Q2 2023, 
compared to USD 8,195 thousand for Q2 2022 and a charge of USD 9,623 thousand for the first six months of 2023 compared to a 
charge of 17,861 thousand for the comparative period. 
The interest expense amounted to USD 5,455 thousand for Q2 2023, compared to USD 5,481 thousand for the comparative period 
in 2022 and USD 10,804 thousand for the first six months of 2023 compared to USD 9,515 thousand for the first six months of 
2022 and mainly related to the bond interest. Interest income generated on cash balances held in Q2 2023 amounted to USD 
4,335 thousand and USD 9,259 thousand for the first six months of 2023 and is higher than the comparative period due mainly to 
higher interest rates.
The unwinding of the asset retirement obligation discount rate amounted to USD 3,474 thousand for Q2 2023, compared to USD 
2,729 thousand for Q2 2022 and USD 6,542 thousand for the first six months of 2023 compared to USD 5,489 thousand for the 
first six months of 2022.
Income tax
The corporate income tax amounted to a charge of USD 9,609 thousand for Q2 2023, compared to a charge of USD 37,452 
thousand for Q2 2022 and a charge of USD 25,220 thousand for the first six months of 2023 compared to a charge of USD 64,950 
for the comparative period. 
The current income tax charge amounted to USD 4,595 thousand in Q2 2023 and USD 8,586 thousand during the first six months 
of 2023 and mainly related to France and Malaysia. No corporate income tax was payable in Canada in respect of the first six 
months of 2023 due to the usage of historical tax pools. 
Capital Expenditure
Development and exploration and evaluation expenditure incurred during the first six months of 2023 was as follows:
USD Thousands Canada –
Southern Assets
Canada –
 Northern Assets Malaysia France Total
Development 8,489 82,701 1,262 14,599 107,051
Exploration and evaluation – – – 9 9
8,489 82,701 1,262 14,608 107,060
Capital expenditure of USD 107,060 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project and on 
the Pad L completion at Onion Lake Thermal and in France on the drilling of the Villeperdue West oil wells.
In addition, USD 5,821 thousand of capital expenditure was spent on the Cor4 assets mainly on drilling from January 1, 2023 to the 
completion date of March 3, 2023.
Cor4 Acquisition
On March 3, 2023, IPC completed the acquisition of all of the issued and outstanding shares of  Cor4 Oil Corp. (“Cor4”). At such 
date, Cor4 became an indirect wholly-owned subsidiary of IPC. On June 1, 2023, Cor4 was amalgamated into IPC Canada Ltd.
The Cor4 acquisition has been accounted for as a business combination with IPC being the acquirer, and in accordance with IFRS 3 
Business Combinations, the assets acquired and liabilities assumed have been recorded at their fair values. 
Total cash consideration paid, after preliminary closing adjustments, amounted to USD 62.2 million (CAD 84.7 million).
19

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
The amounts recognized in respect of the identifiable assets acquired and liabilities assumed are as set out in the table below.
USD Thousands
Cash 2,792
Trade and other receivables  7,671 
Prepaid expenses and deposits  2,417 
Fair value of risk management assets  1,144 
Deferred tax assets  19,334 
Right-of-use assets  109 
Property, plant and equipment  72,242
Accounts payable and accrued liabilities  (12,623)
Right-of-use liabilities  (109)
Decommissioning liabilities  (29,885)
Mark-To-Market reserve in equity  (881)
Total Consideration 62,211
Settled by:
Cash payment 62,211
The Corporation performed a preliminary purchase price allocation for the Cor4 acquisition. The amounts disclosed above were 
determined provisionally pending the finalization of the valuation for those assets and liabilities. Up to twelve months from the 
effective date of the Cor4 acquisition, further adjustments may be made to the fair values assigned to the identifiable assets 
acquired and liabilities assumed. 
Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during the first six 
months of 2023.
 
Decommissioning liabilities
The fair value of the decommissioning liability at the acquisition date was based on the estimated future cash flows to 
decommission the acquired oil and natural gas properties at the end of their useful life. The discount rate used to determine the 
net present value of the decommissioning obligation was a credit risk adjusted rate of 8%.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 28,895 thousand as at June 30, 2023, which included USD 26,948 thousand in 
respect of the FPSO Bertam. The FPSO Bertam is being depreciated on a unit of production basis based based to August 2025, 
being the original Bertam field PSC expiry before PSC extension to 2035.
Financial Position and Liquidity
Financing 
As at January 2022, the Group had a reserve-based lending (RBL) credit facility of USD 140 million in connection with its oil and
gas assets in France and Malaysia and a RBL credit facility of CAD 300 million in connection with its oil and gas assets in Canada. 
In February 2022, IPC completed the issuance of USD 300 million of Bonds, which mature in February 2027 and have a fixed
coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group used a portion of the
proceeds of the Bonds to fully repay the outstanding RBL credit facilities, which were then cancelled. At the same time, the Group
entered into a revolving credit facility of CAD 75 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In Q1 2023, the Group increased the Canadian RCF to CAD 150 million and extended the maturity to May 2025. No cash amounts 
were drawn under the Canadian RCF as at June 30, 2023.
As at June 30, 2023, IPC had a EUR 13 million unsecured credit facility in France (the “France Facility“), with maturity in May 
2026. IPC commenced quarterly repayments of the French Facility in August 2022. The amount remaining outstanding
under the France Facility as at June 30, 2023 was USD 11 million (EUR 10 million).
Total net cash as at June 30, 2023 amounted to USD 64 million.
20

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
IPC intends to fund the Blackrod Phase 1 development with cash on hand and forecast FCF generated by its operations.
The Bond repayment obligations as at June 30, 2023, are classified as non-current as there are no mandatory repayments within 
the next twelve months.
An amount of USD 3.5 million (EUR 3.2 million) drawn under the France Facility as at June 30, 2023 is classified as current 
representing the repayment planned within the next twelve months.
The Group is in compliance with the covenants of the Bonds and its financing facilities as at June 30, 2023.
Cash and cash equivalents held amounted to USD 374 million as at June 30, 2023 of which USD 5.2 million was restricted.
Working Capital 
As at June 30, 2023, the Group had a net working capital balance including cash of USD 375,929 thousand compared to USD 
488,661 thousand as at December 31, 2022. The difference as at June 30, 2023, from December 31, 2022, is mainly a result of 
the lower cash balances held following the Cor4 acquisition and the continuing NCIB program. 
Non-IFRS Measures
In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free
cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do 
not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by 
other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in 
accordance with IFRS.
The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by and
the financial performance and condition of the Corporation. Management also uses non-IFRS measures internally in order to
facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s
ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures
are important supplemental measures of operating performance because they highlight trends in the core business that may
not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for
assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable
between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties
frequently use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the
purpose of presenting information about management’s current expectations and plans relating to the future and readers are
cautioned that such statements may not be appropriate for other purposes.
“Operating cash flow” is calculated as revenue less production costs less current tax. Operating cash flow is used to analyze the
amount of cash that is being generated available for capital investment and servicing debt.
“Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures
less general, administration and depreciation expenses before depreciation and less cash financial items. Free cash flow is used
to analyze the amount of cash that is being generated by the business and that is available for such purposes as repaying debt,
funding acquisitions and returning capital to shareholders.
“EBITDA” is calculated as net result before financial items, taxes, depletion of oil and gas properties, exploration costs,
impairment costs and depreciation and adjusted for non-recurring profit/loss on sale of assets and other income.
“Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is
used to analyze the cash cost of producing the oil and gas volumes.
“Net debt” is calculated as bank loans and Bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash 
equivalents less bank loans and Bonds. 
Reconciliation of Non-IFRS Measures
Operating cash flow
The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended June 30 Six months ended June 30
2023 2022 2023 2022
Revenue 205,564 315,540 398,080 575,322
Production costs (116,597) (118,151) (234,124) (228,700)
Current tax (4,595) (4,874) (8,586) (8,997)
Operating cash flow 84,372 192,515 155,370 337,625 
21

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
The operating cash flow for the first six months of 2023 including the operating cash flow contribution of the Cor4 acquisition from 
the effective date of January 1, 2023 to the completion date of March 3, 2023 amounts to USD 160,272 thousand. 
Free cash flow
The following table sets out how free cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended June 30 Six months ended June 30
2023 2022 2023 2022
Operating cash flow - see above 84,372 192,515 155,370 337,625 
Capital expenditures (58,822) (29,788) (107,060) (68,141)
Abandonment and farm-in expenditures1 (3,717) (2,435) (4,928) (4,360)
General, administration and depreciation expenses before 
depreciation2 (3,766) (3,351) (7,577) (7,121)
Cash financial items3 (1,652) (5,149) (2,300) (9,730)
Free cash flow 16,415 151,792 33,505 248,273
1  See note 17 to the Financial Statements 
2  Depreciation is not specifically disclosed in the Financial Statements
3  See notes 4 and 5 to the Financial Statements.
The free cash flow for the first six months of 2023 including the free cash flow contribution of the Cor4 acquisition from the 
effective date of January 1, 2023 to the completion date of March 3, 2023 amounts to USD 32,674 thousand. 
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended June 30 Six months ended June 30
2023 2022 2023 2022
Net result 32,025 105,217 71,588 186,039 
Net financial items 6,955 15,297 11,970 21,904 
Income tax 9,609 37,452 25,220 64,950 
Depletion 33,362 31,830 39,801 59,782 
Depreciation of other tangible fixed assets 2,436 3,021 4,994 5,101 
Exploration and business development costs 422 829 2,031 930 
Depreciation included in general, administration and depreciation 
expenses1 392 392 775 795 
EBITDA 85,201 194,038 156,379 339,501 
1  Item is not shown in the Financial Statements.
The EBITDA for the first six months of 2023 including the EBITDA contribution of the Cor4 acquisition from the effective date of 
January 1, 2023 to the completion date of March 3, 2023 amounts to USD 161,280 thousand. 
Operating costs
The following table sets out how operating costs is calculated: 
USD Thousands
Three months ended June 30 Six months ended June 30
2023 2022 2023 2022
Production costs 116,597 118,151 234,124 228,700
Cost of blending (40,870) (57,639) (88,687) (100,280)
Change in inventory position 4,560 10,175 10,295 13,728
Operating costs 80,287 70,687 155,732 142,148
The operating costs for the first six months of 2023 including the operating costs contribution of the Cor4 acquisition from the 
effective date of January 1, 2023 to the completion date of March 3, 2023 amounts to USD 162,533 thousand. 
22

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Net cash
The following table sets out how net cash is calculated from figures shown in the Financial Statements: 
USD Thousands June 30, 2023 December 31, 2022
Bank loans (10,629) (12,142)
Bonds (300,000) (300,000)
Cash and cash equivalents 374,177 487,240 
Net cash 63,548 175,098 
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, has issued four letters of credit as follows: (a) CAD 2.6 million in respect of its 
obligations to purchase diluent; (b) CAD 0.8 million in respect of its obligations related to the Ferguson asset, increasing by  
CAD 0.1 million annually to a maximum of CAD 1.0 million; (c) CAD 1.3 million in respect of pipeline access; and (d) CAD 0.5 
million in relation to the hedging of electricity prices. 
Outstanding Share Data 
The common shares of IPC trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2022, IPC had a total of 155,198,105  common shares issued and outstanding, of which IPC held 1,160,651 
common shares in treasury. All common shares held in treasury as at January 1, 2022 were cancelled during January 2022.
During 2022, under the normal course issuer bid/share repurchase program announced in December 2021 and renewed in 
December 2022 (NCIB), IPC purchased and cancelled an aggregate of 8,951,391 common shares.
During Q2 2022, IPC commenced an offer to repurchase common shares under the substantial issuer bid (SIB). Under the SIB,  
IPC purchased and cancelled an aggregate of 8,258,064 common shares. 
As at December 31, 2022, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in 
treasury.
As at June 30, 2023, following the cancellation during the first six months of 2023 of a further 6,330,914 common shares
repurchased under the NCIB, IPC had a total of 130,497,085 common shares issued and outstanding, with no common shares
held in treasury.
Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 40,697,533 
common shares in IPC, representing 31.2% of the outstanding common shares as at June 30, 2023.
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 4,528,333 IPC Share Unit Plan awards outstanding as at August 1, 2023 (10,703 awards granted in January 2020, 25,335 
awards granted in July 2020, 21,216 awards granted in January 2021, 324,811 awards granted in March 2021, 1,716,000 awards 
granted in May 2021, 10,067 awards granted in July 2021 and 12,543 awards granted in January 2022, 1,248,434 awards granted 
in March 2022, 5,487 awards granted in July 2022, 2,072 awards granted in January 2023, 1,148,421 awards granted in March 
2023 and 3,244 awards granted in July 2023).
Contractual Obligations and Commitments 
In Canada, an oil pipeline from the Onion Lake Thermal field to a gathering system has been built by a third party for the exclusive 
use of IPC. The initial investment in the pipeline was met by the pipeline owner and is to be recovered through an agreed tariff 
charged to IPC. IPC has committed to a firm transportation service for 15 years from commencement of service in April 2022, with 
total remaining tariffs committed as shown in the table below:
2023 2024 2025 2026 2027 Thereafter
Transportation service (MCAD) 13.8 28.0 28.4 29.0 28.2 275.2
In Malaysia, IPC has an obligation to make payments towards historic costs on Block PM307 payable on the Bertam field for every 
1 MMboe gross that the field produces above 10 MMboe gross. The estimated liability based on current 2P reserves and which is
capped at cumulative production of 27.5 MMboe gross, has been provided for in the Group’s Balance Sheet  – see Note 17 
Provisions of the Financial Statements.
23

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
Critical Accounting Policies and Estimates
In connection with the preparation of the Corporation’s consolidated financial statements, management has made assumptions 
and estimates about future events and applied judgments that affect the reported values of assets, liabilities, revenues, expenses 
and related disclosures. These assumptions, estimates and judgments are based on historical experience, current trends and other 
factors that they believe to be relevant at the time the financial statements are prepared. The management reviews the accounting 
policies, assumptions, estimates and judgments to ensure that the financial statements are presented fairly in accordance with 
IFRS. However, because future events and their effects cannot be determined with certainty, actual results could differ from these 
assumptions and estimates, and such differences could be material.
Transactions with Related Parties 
During Q2 2023, Lundin Foundation has charged the Group USD 182 thousand in respect of sustainability advisory services 
provided to the Group.
All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with 
parties at arm’s length.
Financial Risk Management 
As an international oil and gas exploration and production company, IPC is exposed to financial risks such as interest rate risk,
currency risk, credit risk, liquidity risks as well as the risk related to the fluctuation in oil and gas prices. The Group seeks to control 
these risks through sound management practice and the use of internationally accepted financial instruments, such as oil and 
gas, condensate and electricity price, interest rate or foreign exchange hedges as the case may be. Financial instruments will be 
solely used for the purpose of managing risks in the business. As at June 30, 2023, the Corporation had entered into oil and gas, 
condensate and electricity price hedges – see below.
Management believes that the cash resources, other current assets and cash flow from operations are sufficient to finance the
Group’s operations and capital expenditures program over the next year.
Capital Management
The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its
committed financial liabilities and work program requirements in order to create shareholder value. The Group may put in place
new bonds or credit facilities, repay debt, or pursue other such restructuring activities as appropriate.
Management of the Corporation will continuously monitor and manage the Group’s capital, liquidity and net debt position in order
to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility.
Price of Oil and Gas
Prices of oil and gas are affected by the normal economic drivers of supply and demand as well as by financial investors and 
market uncertainty. Factors that influence these prices include operational decisions, prices of competing fuels, natural disasters, 
economic conditions, transportation constraints, political instability or conflicts or actions by major oil exporting countries. Price 
fluctuations will affect the Group’s financial position. 
Based on analysis of the circumstances, management assesses the benefits of forward hedging monthly sales contracts for the 
purpose of protecting cash flow. If management believes that a hedging contract will appropriately help manage cash flow then it 
may choose to enter into a commodity price hedge. The Group does not currently have any covenants under its current financing 
facilities to hedge future production.
The Group had gas price sale financial hedges outstanding as at June 30, 2023, which are summarized as follows:
Period Volume (Gigajoules (GJ) per day) Type Average Pricing 
July 1, 2023 – October 31, 2023 35,0001 AECO Swap CAD 3.95/GJ 
1  Equivalent to 33,700 Mcf per day at CAD 4.10/Mcf.
The Group had oil price sale financial hedges outstanding as at June 30, 2023 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing 
July 1, 2023 - December 31, 2023 12,000 WCS/ARV Differential USD -10.08/bbl
January 1, 2024 - December 31, 2024 8,500 WCS/WTI Differential USD -13.91/bbl
24

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
The Group had condensate financial hedges outstanding as at June 30, 2023 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
October 31, 2023 – March 31, 2024 3,000 C5/WTI Differential USD -1.60/bbl 
The Group had electricity financial hedges outstanding as at June 30, 2023 which are summarized as follows:
Period Volume (MW) Type Pricing 
July 1, 2023 –  July 31, 2023 5 AESO CAD 72.95/MWh 
October 1, 2025 - September 1, 2040 3 AESO CAD 75.00/MWh
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had 
a positive fair value of USD 5,920 thousand as at June 30, 2023.
Currency Risk
The Group’s policy on currency rate hedging is, in the case of currency exposure, to consider fixing the rate of exchange. The 
Group will take into account the currency exposure, current rates of exchange and market expectations in comparison to historic 
trends and volatility in making the decision to hedge.
In October 2022, IPC entered into currency hedge swaps for 2023 to buy CAD 15 million per month, sell USD at an average
exchange rate of 1.3619 and to buy EUR 3 million per month, sell USD at an average exchange rate of 1.0000. In June 2023, IPC 
entered into currency hedge swaps for the second six months of 2023 to buy MYR 13 million per month, sell USD at an average 
exchange rate of 4.5. This is to partially fund operational expenditures in those currencies in Canada, France and Malaysia respectively.
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The currency 
hedge swaps had a positive fair value of USD 3,292 thousand as at June 30, 2023.
Interest Rate Risk
Interest rate risk is the risk to earnings due to uncertain future interest rates on borrowings. The Group will take into account the 
level of external debt, current interest rates and market expectations in comparison to historic trends and volatility in making the 
decision to hedge.
Credit Risk
The Group may be exposed to third party credit risk through contractual arrangements with counterparties who buy the Group’s 
hydrocarbon products. The Group’s policy is to limit credit risk by only entering into oil and gas sales agreements with reputable 
and creditworthy oil and gas and trading companies. Where it is determined that there is a credit risk for oil and gas sales, the 
Group’s policy is to require credit enhancement from the purchaser.
The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take 
possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In 
addition, cash is to be held and transacted only through major banks.
RISK AND UNCERTAINTIES 
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, 2022 (”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 Resource Advisory” in this MD&A. 
25

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
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 six month period ended June 
30, 2023, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial reporting. 
Control Framework 
Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control 
– Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission 
(COSO).   
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 
This MD&A contains statements and information which constitute “forward-looking statements“ or “forward-looking information“ 
(within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements“) 
relate to future events, including the Corporation’s future performance, business prospects or opportunities. Actual results may differ 
materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this MD&A 
are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this MD&A, unless 
otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except 
as required by applicable laws. 
All statements other than statements of historical fact may be forward-looking statements. Any statements that express or involve 
discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, guidance, budgets, objectives, assumptions 
or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“, “continue“, 
“estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, “might“, “should“, 
“believe“, “budget“ and similar expressions) are not statements of historical fact and may be “forward-looking statements“.
 
Forward-looking statements include, but are not limited to, statements with respect to: 
• 2023 production range, operating costs, operating cash flow, free cash flow, and capital and decommissioning expenditure 
estimates; 
• Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business 
plans and assumptions regarding the business environment, which are subject to change; 
• IPC’s financial and operational flexibility to continue to react to recent events and navigate the Corporation through periods of 
volatile commodity prices; 
• IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the 
Corporation;
• The ability to fully fund future expenditures from cash flows and current borrowing capacity; 
• IPC’s ability to maintain operations, production and business in light of any future pandemics and the restrictions and 
disruptions related thereto, including risks related to production delays and interruptions, changes in laws and regulations and 
reliance on third-party operators and infrastructure; 
• IPC’s intention and ability to continue to implement our 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; 
• Future development potential of the Suffield and Ferguson operations in Canada, including the timing and success of future 
oil and gas drilling and optimisation programs; 
• 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 drilling pad production and timing and success of facility upgrades, tie-in work and infill drilling at Onion 
Lake Thermal;
• The ability of IPC to achieve and maintain current and forecast production and take advantage of production growth and 
development upside opportunities related to the assets acquired in the Cor4 acquisition;
• The potential improvement in the Canadian oil egress situation and IPC’s ability to benefit from any such improvements;
• The timing and success of the future development projects and other organic growth opportunities in France; 
• The ability to maintain current and forecast production in France; 
• The ability of IPC to achieve and maintain current and forecast production in Malaysia; 
• The ability to IPC to acquire further common shares under the NCIB, including the timing of any such purchases;
26

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
• The return of value to IPC’s shareholders as a result of the NCIB;
• The ability of IPC to implement further shareholder distributions in addition to the NCIB;
• IPC’s ability to implement its GHG emissions intensity and climate strategies and to achieve its net GHG emissions intensity 
reduction targets;
• Estimates of reserves and contingent resources; 
• The ability to generate free cash flows and use that cash to repay debt; 
• IPC’s ability to identify and complete future acquisitions; 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 Resource Advisory“.
The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations 
and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; 
interest rates; future well production rates and reserve and contingent resource volumes; operating costs; 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; the benefits of acquisitions; 
the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally; 
the availability and cost of financing, labour and services; 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;
• 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; 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 and Uncertainties”
Estimated FCF generation is based on IPC’s current business plans over the periods of 2023 to 2027 and 2028 to 2032. 
Assumptions include average net production of approximately 50 Mboepd over the period of 2023 to 2027, average net production 
of approximately 65 Mboepd over the period of 2028 to 2032, average Brent oil prices of USD 75 to 95 per boe 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, 2022, (See “Cautionary 
Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk and Uncertainties”) 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 release. 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.
27

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
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 (other than the assets acquired in the Cor4 acquisition) are effective as of December 31, 2022, 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, 2022 price forecasts. 
Reserve estimates and estimates of future net revenue in respect of IPC’s oil and gas assets acquired in the Cor4 acquisition 
are effective as of December 31, 2022, and have been audited by GLJ Ltd. (GLJ), an independent qualified reserves auditor, in 
accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 31, 2022, 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, 2022, 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, 2022 price forecasts. 
The price forecasts used in the Sproule, GLJ 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, 2022 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 487 MMboe as at December 31, 2022 (including 15.9 
MMboe acquired in the Cor4 acquisition), by the mid-point of the 2023 CMD production guidance of 48,000 to 50,000 boepd.
The product types comprising the 2P reserves described in this MD&A are contained in the AIF . See also “Supplemental 
Information regarding Product Types” below. Light, medium and heavy crude oil 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 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% probability that the quantities actually recovered will equal or 
exceed the best estimate.
28

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

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
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 
considerations  can be clearly defined. Chance of development is the probability of a project being commercially viable. 
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 
guidance  for contingent resources, the chance of commerciality is solely based on the chance of development associated with 
the resolution of all contingencies required for the re-classification of the contingent resources as reserves. Therefore   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 the 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 the MD&A.
2P reserves and contingent resources included in the reports prepared by Sproule, GLJ and ERCE in respect of IPC’s oil and gas 
assets in Canada, France and Malaysia have been aggregated by IPC. Estimates of reserves, resources and future net revenue for 
individual properties may not reflect the same level of confidence as estimates of reserves, resources and future net revenue for 
all properties, due to aggregation. This MD&A contains estimates of the net present value of the future net revenue from IPC’s 
reserves and contingent resources. The estimated values of future net revenue disclosed in this MD&A do not represent fair 
market value. There is no assurance that the forecast prices and cost assumptions used in the reserve and resources evaluations 
will be attained and variances could be material.
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.  
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel 
(bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value 
equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and 
crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an 
indication of value.
Supplemental Information regarding Product Types
The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily 
production figures provided in this document:
Heavy Crude Oil 
(Mbopd)
Light and Medium 
Crude Oil (Mbopd)
Conventional Natural Gas
(per day)
Total
(Mboepd)
Three months ended
June 30, 2023 25.3 9.2 104.0 MMcf                     
(17.3 Mboe) 51.8
June 30, 2022 22.9 9.9 99.6 MMcf 
(16.6 Mboe) 49.4
Six months ended
June 30, 2023 26.0 9.4 102.0 MMcf
(17.0 Mboe) 52.3
June 30, 2022 22.6 8.9
96.6 MMcf
(16.1 Mboe)
47.6
Year ended December 31, 2022
December 31, 2022 22.6 9.6 98.1MMcf                     
(16.4 Mboe) 48.6
This document also makes reference to IPC’s forecast average daily production of 48,000 to 50,000 boepd for 2023. IPC 
estimates that approximately 50% of that production will be comprised of heavy oil, approximately 17% will be comprised of light 
and medium crude oil and approximately 33% will be comprised of conventional natural gas.
29

===== SIDA 52 =====

Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
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
    Alkaline surfactant polymer (an EOR process)
ARV  Argus WCS Houston (a reference price for the cost of transporting WCS quality oil from Alberta to Houston)
bbl   Barrel (1 barrel = 159 litres)
boe1   Barrels of oil equivalents
boepd   Barrels of oil equivalents per day
bopd   Barrels of oil per day
Bcf  Billion cubic feet
Bscf   Billion standard cubic feet 
C5  Condensate
CO2e  Carbon dioxide equivalents, including carbon dioxide, methane and nitrous oxide
Empress   The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border
EOR   Enhanced Oil Recovery
GJ  Gigajoules
Mbbl   Thousand barrels
MMbbl   Million barrels
Mboe   Thousand barrels of oil equivalents 
Mboepd   Thousand barrels of oil equivalents per day
Mbopd   Thousand barrels of oil per day
MMboe   Million barrels of oil equivalents
MMbtu   Million British thermal units
Mcf   Thousand cubic feet
Mcfpd  Thousand cubic feet per day
MMcf   Million cubic feet
MW  Mega watt
MWh  Mega watt per hour
NGL   Natural gas liquid
SAGD   Steam assisted gravity drainage (a thermal recovery process)
WTI   West Texas Intermediate (a light oil reference price)
WCS   Western Canadian Select (a heavy oil reference price)
1  All volume references to boe are calculated on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) 
unless otherwise indicated. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and 
does not represent a value equivalency at the wellhead. BOEs may be misleading, particularly if used in isolation. Given that the value ratio based 
on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 
6:1 basis may be misleading as an indication of value.
30

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Management’s Discussion and Analysis
For the three and six months ended June 30, 2023
DIRECTORS
C. Ashley Heppenstall
Director, Chair
London, England
Mike Nicholson
Director, President and Chief Executive Officer
Geneva, Switzerland
Chris Bruijnzeels
Director
Abcoude, The Netherlands
Donald K. Charter
Director
Toronto, Ontario, Canada
Emily Moore
Director
Toronto, Ontario, Canada
Lukas (Harry) H. Lundin
Director
Toronto, Ontario, Canada
OFFICERS
Christophe Nerguararian
Chief Financial Officer
Geneva, Switzerland
William Lundin
Chief Operating Officer
Geneva, Switzerland
Jeffrey Fountain
General Counsel and Corporate Secretary
Geneva, Switzerland
Rebecca Gordon
VP 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
MEDIA AND INVESTOR RELATIONS
Robert Eriksson 
Stockholm, Sweden
Sophia Shane
Vancouver, British Columbia, Canada
CORPORATE OFFICE
Suite 2000 – 885 West Georgia Street Vancouver, 
British Columbia V6C 3E8 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 2600 - 595 Burrard Street 
Vancouver, British Columbia
V7X 1L3 Canada
INDEPENDENT AUDITORS
PricewaterhouseCoopers SA, Switzerland
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta, and Toronto, Ontario
STOCK EXCHANGE LISTINGS
Toronto Stock Exchange and NASDAQ Stockholm 
Trading Symbol: IPCO
31

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Corporate Office
International Petroleum Corp
Suite 2000
885 West Georgia Street
Vancouver, BC
V6C 3E8, Canada
Tel: +1 604 689 7842
E-mail: info@international-petroleum.com
Web: international-petroleum.com□