FULLTEXT DEL 1 AV 1
Kvartalsrapport Q2 2024
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Q2
International Petroleum Corporation
Interim Condensed Consolidated
Financial Statements
For the three and six months ended June 30, 2024
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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, 2024 and 2023, UNAUDITED
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3
Interim Condensed Consolidated Statement of Operations
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
Three months ended June 30 Six months ended June 30
USD Thousands Note 2024 2023 2024 2023
Revenue 2 219,040 205,564 425,459 398,080
Cost of sales
Production costs 3 (111,381) (116,597) (227,126) (234,124)
Depletion and decommissioning costs 8 (32,661) (33,362) (65,814) (39,801)
Depreciation of other tangible fixed assets 8 (2,218) (2,436) (4,480) (4,994)
Exploration and business development costs (72) (422) (147) (2,031)
Gross profit 2 72,708 52,747 127,892 117,130
General, administration and depreciation expenses (3,980) (4,158) (7,929) (8,352)
Profit before financial items 68,728 48,589 119,963 108,778
Finance income 4 4,917 4,335 10,534 9,259
Finance costs 5 (14,965) (11,290) (30,352) (21,229)
Net financial items (10,048) (6,955) (19,818) (11,970)
Profit before tax 58,680 41,634 100,145 96,808
Income tax expense 6 (13,470) (9,609) (21,216) (25,220)
Net result 45,210 32,025 78,929 71,588
Net result attributable to:
Shareholders of the Parent Company 45,202 32,017 78,914 71,574
Non-controlling interest 8 8 15 14
45,210 32,025 78,929 71,588
Earnings per share – USD1 14 0.36 0.24 0.63 0.53
Earnings per share fully diluted – USD1 14 0.36 0.24 0.62 0.52
1 Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the interim condensed consolidated financial statements
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4
Interim Condensed Consolidated Statement of Comprehensive Income
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
Three months ended June 30 Six months ended June 30
USD Thousands Note 2024 2023 2024 2023
Net result 45,210 32,025 78,929 71,588
Other comprehensive income
Items that may be reclassified to profit or loss:
Reclassification of hedging (gains)/losses to profit or
loss 2 2,644 (1,531) (6,562) (10,115)
Gain/(loss) on cash flow hedges 10,653 3,954 (34,766) 8,613
Income tax relating to these items (3,070) (641) 9,933 345
Currency translation adjustments (8,839) 15,734 (31,211) 16,911
Total comprehensive income 46,598 49,541 16,323 87,342
Total comprehensive income attributable to:
Shareholders of the Parent Company 46,600 49,541 16,323 87,333
Non-controlling interest (2) – – 9
46,598 49,541 16,323 87,342
See accompanying notes to the interim condensed consolidated financial statements
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5
Interim Condensed Consolidated Balance Sheet
As at June 30, 2024 and December 31, 2023, UNAUDITED
USD Thousands Note June 30, 2024 December 31, 2023
ASSETS
Non-current assets
Exploration and evaluation assets 7 630 –
Property, Plant and Equipment 8 1,402,390 1,303,860
Right-of-use assets 2,438 2,814
Deferred tax assets 6 1,041 1,827
Derivative instruments 18 502 7,049
Other assets 9 55,922 56,838
Total non-current assets 1,462,923 1,372,388
Current assets
Inventories 10 20,460 21,808
Trade and other receivables 11 130,383 113,497
Derivative instruments 18 5,419 35,504
Current tax receivables 193 2,714
Cash and cash equivalents 12 368,797 517,074
Total current assets 525,252 690,597
TOTAL ASSETS 1,988,175 2,062,985
LIABILITIES
Non-current liabilities
Financial liabilities 15, 18 3,526 5,442
Bonds 15, 18 437,439 435,041
Lease liabilities 2,204 2,087
Provisions 16 252,088 250,657
Deferred tax liabilities 6 88,544 86,348
Derivative instruments 18 1,120 263
Total non-current liabilities 784,921 779,838
Current liabilities
Trade and other payables 17 155,286 188,871
Financial liabilities 15, 18 3,491 3,589
Derivative instruments 18 5,854 1,267
Current tax liabilities 5,147 255
Lease liabilities 340 809
Provisions 16 6,917 8,097
Total current liabilities 177,035 202,888
EQUITY
Shareholders’ equity 1,026,075 1,080,074
Non-controlling interest 144 185
Net shareholders’ equity 1,026,219 1,080,259
TOTAL EQUITY AND LIABILITIES 1,988,175 2,062,985
Approved by the Board of Directors
(Signed) C. Ashley Heppenstall (Signed) William Lundin
Director Director
See accompanying notes to the interim condensed consolidated financial statements
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6
Interim Condensed Consolidated Statement of Cash Flow
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
Three months ended June 30 Six months ended June 30
USD Thousands Note 2024 2023 2024 2023
Cash flow from operating activities
Net result 45,210 32,025 78,929 71,588
Adjustments for non-cash related items:
Depletion, depreciation and amortization 8 35,171 36,199 70,881 45,579
Income tax 6 13,470 9,609 21,216 25,220
Amortization of capitalized financing fees 5 426 338 851 781
Foreign currency exchange loss/(gain) 5 1,556 1,491 3,617 2,347
Interest income 4 (4,917) (4,335) (10,534) (9,259)
Interest expense 5 8,928 5,455 17,746 10,804
Unwinding of asset retirement obligation discount 5 3,641 3,474 7,259 6,542
Share-based costs 2,242 2,353 4,176 4,940
Other 204 237 475 415
Cash flow generated from operations (before
working capital adjustments and income taxes) 105,931 86,846 194,616 158,957
Changes in working capital (22,067) 7,949 (71,027) (6,644)
Decommissioning costs paid 16 (2,241) (3,160) (2,363) (4,371)
Other payments 16 – (574) (504) (864)
Net income taxes refunded/(paid) 3,742 (22,490) 277 (26,074)
Interest received 3,268 2,800 8,279 7,765
Interest paid (48) (14) (16,414) (10,961)
Net cash flow from operating activities 88,585 71,357 112,864 117,808
Cash flow used in investing activities
Investment in property, plant and equipment 7,8 (84,175) (59,067) (209,486) (107,477)
Acquisitions net of cash acquired – (239) – (59,419)
Net cash (outflow) from investing activities (84,175) (59,306) (209,486) (166,896)
Cash flow from financing activities
Repayments 15 (945) (880) (2,014) (1,736)
Paid financing fees – – – (507)
Repurchase of own shares (“NCIB”) 13 (28,430) (14,325) (45,738) (60,155)
Other payments (249) (259) (472) (445)
Net cash (outflow) from financing activities (29,624) (15,464) (48,224) (62,843)
Change in cash and cash equivalents (25,214) (3,413) (144,846) (111,931)
Cash and cash equivalents at the beginning of the
period 397,390 378,466 517,074 487,240
Currency exchange difference in cash and cash
equivalents (3,379) (876) (3,431) (1,132)
Cash and cash equivalents at the end of the period 368,797 374,177 368,797 374,177
See accompanying notes to the interim condensed consolidated financial statements
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7
Interim Condensed Consolidated Statement of Changes in Equity
For the three and six months ended June 30, 2024 and 2023, 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, 2024 230,005 808,846 (10,745) 18,838 31,344 1,786 1,080,074 185 1,080,259
Net result – 78,914 – – – – 78,914 15 78,929
Cash flow hedge – – – – (31,395) – (31,395) – (31,395)
Currency translation difference – – (28,227) (2,221) (748) – (31,196) (15) (31,211)
Total comprehensive income – 78,914 (28,227) (2,221) (32,143) – 16,323 – 16,323
Repurchase of own shares
(NCIB)1 (46,627) – – – – – (46,627) – (46,627)
Dividend distribution – – – – – – – (41) (41)
Share based costs – – – 4,176 – – 4,176 – 4,176
Share based payments2 (21,740) – – (6,131) – – (27,871) – (27,871)
Balance at June 30, 2024 161,638 887,760 (38,972) 14,662 (799) 1,786 1,026,075 144 1,026,219
1 See Note 13
2 The third instalment of IPC RSP 2021 awards, the second instalment of IPC RSP 2022 awards, the first instalment of IPC RSP 2023 awards and
the IPC PSP 2021 awards vested on January 31, 2024, at a price of CAD 14.90 per award. The difference between the value at vesting date
and at grant (respectively CAD 4.07 per award, CAD 9.09 per award, CAD 14.27 per award and CAD 3.61 per award) was offset against 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, 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
Acquisitions – – – – 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 shares
(NCIB)1 (60,156) – – – – – (60,156) – (60,156)
Share based costs – – – 17,393 – – 17,393 – 17,393
Share based payments2 (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 13
2 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.
See accompanying notes to the interim condensed consolidated financial statements
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8
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, 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 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business
address is Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
B. Basis of preparation
The unaudited interim condensed consolidated financial statements have been prepared in accordance with International
Accounting Standard 34, Interim Financial Reporting (“IAS 34”) using accounting policies consistent with IFRS Accounting
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The unaudited interim consolidated
financial statements should be read in conjunction with IPC’s annual consolidated financial statements for the year ended
December 31, 2023, 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 July 30, 2024.
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, 2023.
C. Change in presentation
The following items within the interim condensed consolidated balance sheet were reclassified to conform to the current year’s
presentation:
• Oil and gas properties and other tangible fixed assets, formerly presented separately as “Oil and gas properties” and “Other
tangible fixed assets”, are now presented together on the interim condensed consolidated balance sheet as “Property, Plant
and Equipment”. Refer to Note 8.
D. Going concern
The Group’s interim condensed consolidated financial statements for the six months period ended June 30, 2024, have been
prepared on a going concern basis, which assumes that the Group will be able to realize its assets and discharge its liabilities in the
normal course of business as they become due in the foreseeable future.
E. Changes in accounting policies and disclosures
During the six months ended June 30, 2024, the Group has applied the accounting standards, interpretations and annual
improvement points that are effective as of January 1, 2024.
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9
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
2. SEGMENT INFORMATION
The Group operates within several geographical areas. Operating segments are reported at a country level which is consistent with
the internal reporting provided to the CEO, who is the chief operating decision maker.
The following tables present segment information regarding: revenue, production costs, other operating costs and gross profit/
(loss). The Group derives its revenue from contracts with customers primarily through the transfer of oil and gas at a point in time.
In addition, certain identifiable asset segment information is reported in Note 7 and 8.
Three months ended June 30, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 191,018 39,341 17,253 – 247,612
NGLs 275 – – – 275
Gas 6,675 – – – 6,675
Net sales of oil and gas 197,968 39,341 17,253 – 254,562
Change in under/over lift position – – 2,215 – 2,215
Royalties (34,289) – (1,161) – (35,450)
Hedging settlement (2,644) – – – (2,644)
Other operating revenue – – 237 120 357
Revenue 161,035 39,341 18,544 120 219,040
Operating costs (49,801) (7,229) (7,804) – (64,834)
Cost of blending (41,675) – – – (41,675)
Change in inventory position (96) (4,829) 53 – (4,872)
Depletion and decommissioning costs (22,486) (6,893) (3,282) – (32,661)
Depreciation of other tangible fixed assets – (2,218) – – (2,218)
Exploration and business development costs – – – (72) (72)
Gross profit/(loss) 46,977 18,172 7,511 48 72,708
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
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10
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
Six months ended June 30, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 360,634 57,894 33,970 – 452,498
NGLs 519 – – – 519
Gas 21,092 – – – 21,092
Net sales of oil and gas 382,245 57,894 33,970 – 474,109
Change in under/over lift position – – 5,131 – 5,131
Royalties (58,772) – (2,300) – (61,072)
Hedging settlement 6,562 – – – 6,562
Other operating revenue – – 454 275 729
Revenue 330,035 57,894 37,255 275 425,459
Operating costs (109,690) (14,245) (16,715) – (140,650)
Cost of blending (86,881) – – – (86,881)
Change in inventory position 43 210 152 – 405
Depletion and decommissioning costs (45,390) (13,923) (6,501) – (65,814)
Depreciation of other tangible fixed assets – (4,480) – – (4,480)
Exploration and business development costs – – – (147) (147)
Gross profit/(loss) 88,117 25,456 14,191 128 127,892
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.
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11
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
3. PRODUCTION COSTS
Three months ended June 30 Six months ended June 30
USD Thousands 2024 2023 2024 2023
Cost of operations 54,183 69,378 119,196 134,152
Tariff and transportation expenses 9,387 9,559 18,930 19,058
Direct production taxes 1,264 1,350 2,524 2,522
Operating costs 64,834 80,287 140,650 155,732
Cost of blending1 41,675 40,870 86,881 88,687
Change in inventory position 4,872 (4,560) (405) (10,295)
Total production costs 111,381 116,597 227,126 234,124
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 2024 2023 2024 2023
Interest income 4,917 4,335 10,534 9,259
Total finance income 4,917 4,335 10,534 9,259
5. FINANCE COSTS
Three months ended June 30 Six months ended June 30
USD Thousands 2024 2023 2024 2023
Foreign exchange loss, net 1,556 1,491 3,617 2,347
Interest expense 8,928 5,455 17,746 10,804
Unwinding of asset retirement obligation discount 3,641 3,474 7,259 6,542
Amortization of financing fees 74 59 159 223
Amortization of loan fees 426 279 851 558
Loan commitment fees 223 186 445 274
Other financial costs 117 346 275 481
Total finance costs 14,965 11,290 30,352 21,229
6. INCOME TAX
Three months ended June 30 Six months ended June 30
USD Thousands 2024 2023 2024 2023
Current tax (5,718) (4,595) (7,091) (8,586)
Deferred tax (7,752) (5,014) (14,125) (16,634)
Total tax expense (13,470) (9,609) (21,216) (25,220)
The Group is within the scope of the OECD Pillar Two model rules. Pillar Two legislation is enacted or expected to be enacted in all
relevant Group entities in 2024, and with effect from January 1, 2024. The Group applies the exception to recognising and disclosing
information about deferred tax assets and liabilities related to Pillar Two income taxes, as provided in the amendments to IAS 12
issued in May 2023. All relevant entities within the Group have an effective tax rate that exceeds 15% and as such the impact is
insignificant.
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12
Specification of deferred tax assets and tax liabilities1
USD Thousands June 30, 2024 December 31, 2023
Unused tax loss carry forward 23,360 34,446
Derivative hedges 191 –
Other 5,168 5,959
Deferred tax assets 28,719 40,405
Accelerated allowances 116,209 115,399
Derivative hedges 13 9,527
Deferred tax liabilities 116,222 124,926
Deferred taxes, net (87,503) (84,521)
1 The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the
balance sheet when they relate to the same jurisdiction.
The deferred tax liabilities consist of accelerated allowances, being the difference between the book and the tax value of oil and
gas properties and site restoration provisions. The deferred tax liabilities will be released over the life of the oil and gas assets as
the book value is depleted for accounting purposes.
Deferred tax assets in relation to tax loss carried forwards are only recognized in so far that there is a reasonable certainty as to
the timing and the extent of their realization. The recognized unused tax loss carry forward mainly relates to Canada. The Group
has concluded that the deferred assets will be recoverable using the estimated future taxable income based on the approved
business plans and budgets.
7. EXPLORATION AND EVALUATION ASSETS
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 – – – –
Additions 147 483 – 630
Net book value June 30, 2024 147 483 – 630
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 – – 4,764 4,764
Additions – – 39 39
Write-off – – (39) (39)
Reclassification – – (4,937) (4,937)
Currency translation adjustments – – 173 173
Net book value December 31, 2023 – – – –
8. PROPERTY, PLANT AND EQUIPMENT
USD Thousands 2024 2023
Oil and gas properties 1,381,513 1,278,422
Other tangible fixed assets 20,877 25,438
Property, Plant and Equipment 1,402,390 1,303,860
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
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13
Oil and gas properties
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 1,465,010 591,123 436,693 2,492,826
Additions 191,912 15,003 1,812 208,727
Change in estimates 582 – – 582
Currency translation adjustments (50,172) – (13,525) (63,697)
June 30, 2024 1,607,332 606,126 424,980 2,638,438
Accumulated depletion
January 1, 2024 (398,288) (502,834) (313,282) (1,214,404)
Depletion charge for the period (45,390) (13,923) (6,501) (65,814)
Currency translation adjustments 13,575 – 9,718 23,293
June 30, 2024 (430,103) (516,757) (310,065) (1,256,925)
Net book value June 30, 2024 1,177,229 89,369 114,915 1,381,513
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 1,089,789 566,606 399,237 2,055,632
Acquisitions 72,242 – – 72,242
Additions 278,613 17,873 16,204 312,690
Disposals1 (7,854) – – (7,854)
Change in estimates 24,454 6,644 1,738 32,836
Reclassification (22,857) – 4,937 (17,920)
Currency translation adjustments 30,623 – 14,577 45,200
December 31, 2023 1,465,010 591,123 436,693 2,492,826
Accumulated depletion
January 1, 2023 (323,273) (485,034) (288,714) (1,097,021)
Depletion charge for the period (94,192) (17,800) (14,018) (126,010)
Disposals1 4,474 – – 4,474
Other2 22,857 – – 22,857
Currency translation adjustments (8,154) – (10,550) (18,704)
December 31, 2023 (398,288) (502,834) (313,282) (1,214,404)
Net book value December 31, 2023 1,066,722 88,289 123,411 1,278,422
1 In Canada, includes the disposal of non-core properties in the John Lake area.
2 In Canada, includes an adjustment in the first quarter of 2023 for accelerated decommissioning activities funded by a non-cash site rehabilitation
program.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
===== SIDA 14 =====
14
Other tangible fixed assets
USD Thousands FPSO Other Total
Cost
January 1, 2024 204,853 10,048 214,901
Additions – 129 129
Currency translation adjustments – (274) (274)
June 30, 2024 204,853 9,903 214,756
Accumulated depreciation
January 1, 2024 (181,123) (8,340) (189,463)
Depreciation charge for the period (4,480) (156) (4,636)
Currency translation adjustments – 220 220
June 30, 2024 (185,603) (8,276) (193,879)
Net book value June 30, 2024 19,250 1,627 20,877
USD Thousands FPSO Other Total
Cost
January 1, 2023 204,853 9,779 214,632
Additions – 510 510
Disposals – (487) (487)
Currency translation adjustments – 246 246
December 31, 2023 204,853 10,048 214,901
Accumulated depreciation
January 1, 2023 (173,311) (7,947) (181,258)
Depreciation charge for the period (7,812) (684) (8,496)
Disposals – 487 487
Currency translation adjustments – (196) (196)
December 31, 2023 (181,123) (8,340) (189,463)
Net book value December 31, 2023 23,730 1,708 25,438
The Floating Production Storage and Offloading facility (“FPSO“) located on the Bertam field, Malaysia, is being depreciated on
a unit of production basis using the Bertam field 2P reserves to August 2025, being the original Bertam field PSC expiry date,
before the 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, 2024 and 2023, UNAUDITED
===== SIDA 15 =====
15
9. OTHER NON-CURRENT ASSETS
USD Thousands June 30, 2024 December 31, 2023
Financial assets 40,895 41,332
Intangible assets 15,027 15,506
55,922 56,838
Financial assets mainly represent cash payments made to an asset retirement obligation fund for the Bertam field, Malaysia
for an amount of USD 29.0 million (2023: USD 28.7 million). Financial assets also include secured amounts of USD 7.7 million
towards the future asset retirement obligation for the Bertam field and cash-collaterized guarantees placed in 2023 in respect of
work commitments in Malaysia amounting to USD 4.0 million.
Intangible assets mainly represent carbon offsets purchased in Canada.
10. INVENTORIES
USD Thousands June 30, 2024 December 31, 2023
Hydrocarbon stocks 13,373 13,530
Well supplies and operational spares 7,087 8,278
20,460 21,808
11. TRADE AND OTHER RECEIVABLES
USD Thousands June 30, 2024 December 31, 2023
Trade receivables 97,704 97,264
Underlift 6,077 1,029
Joint operations debtors 1,578 910
Prepaid expenses and accrued income 22,859 10,986
Other 2,165 3,308
130,383 113,497
12. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include only cash at hand or held in bank accounts.
13. SHARE CAPITAL
The Corporation’s issued common share capital is as follows:
Number of shares
Balance at January 1, 2023 136,827,999
Cancellation of repurchased common shares (NCIB) (9,835,933)
Balance at December 31, 2023 126,992,066
Cancellation of repurchased common shares (NCIB) (3,720,181)
Balance at June 30, 2024 123,271,885
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2023, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in
treasury.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
===== SIDA 16 =====
16
During 2023, under the normal course issuer bid/share repurchase program announced in December 2022 and renewed in
December 2023 (NCIB), IPC purchased and cancelled an aggregate of 9,835,933 common shares.
As at December 31, 2023, IPC had a total of 126,992,066 common shares issued and outstanding, with no common shares
held in treasury.
During the first six months of 2024, IPC purchased and cancelled a total of 3,720,181 common shares under the NCIB. The
average price of common shares purchased during the first six months of 2024 was SEK 126/ CAD 16 per share.
As at June 30, 2024, IPC had a total of 123,271,885 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.
14. EARNINGS PER SHARE
Basic earnings per share are based on net result attributable to the common shareholders and is calculated based upon the
weighted-average number of common shares outstanding during the periods presented.
Three months ended June 30 Six months ended June 30
2024 2023 2024 2023
Net result attributable to shareholders of the Parent Company, USD 45,201,621 32,016,905 78,913,683 71,574,459
Weighted average number of shares for the period 125,414,090 132,052,470 126,216,022 134,396,105
Earnings per share, USD 0.36 0.24 0.63 0.53
Weighted average diluted number of shares for the period 127,026,090 134,600,024 127,828,022 136,943,660
Earnings per share fully diluted, USD 0.36 0.24 0.62 0.52
15. FINANCIAL LIABILITIES
USD Thousands June 30, 2024 December 31, 2023
Current bank loans 3,491 3,589
Non current bank loans 3,526 5,442
Bonds 441,835 440,288
Capitalized financing fees (4,396) (5,247)
444,456 444,072
As at January 2023, IPC had USD 300 million of bonds outstanding, issued in February 2022 and maturing in February 2027 with a
fixed coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group also had a revolving
credit facility of CAD 75 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In Q3 2023, IPC completed a tap issue of USD 150 million under IPC’s existing 7.25% bond framework issued at 7% discount
to par value with proceeds amounting to USD 139.5 million before transaction costs. For accounting purposes, the discounted
amount was recognised in the balance sheet and the discount will be unwound over the period to maturity of the bond and
charged to the interest expense line of the Statement of Operations using the effective interest rate methodology. As at
June 30, 2024, IPC had a nominal USD 450 million of bonds outstanding with maturity in February 2027. The bond repayment
obligations as at June 30, 2024, are classified as non-current as there are no mandatory repayments within the next twelve
months.
During 2023, the Group increased the Canadian RCF from MCAD 75 to MCAD 180 and extended the maturity to May 2025. During
Q2 2024, the Group extended the maturity of the Canadian RCF to May 2026. As at June 30, 2024, operational letters of credit in
an aggregate of MCAD 40.2 have been issued under the Canadian RCF , including letters of credit issued in June 2024 for a total
amount of MCAD 35 to support the third party pipeline construction agreements for the Blackrod project during 2024 and 2025.
As at June 30, 2024, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May
2026. IPC makes quarterly repayments of the French Facility and the amount remaining outstanding under the France Facility as at
June 30, 2024 was USD 7 million (EUR 6 million). An amount of USD 3.5 million (EUR 3.2 million) drawn under the France Facility
as at June 30, 2024 is classified as current representing the repayment planned within the next twelve months.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
===== SIDA 17 =====
17
The Group is in compliance with the covenants of the bonds and its financing facilities as at June 30, 2024.
Total net debt as at June 30, 2024 amounted to USD 88 million. Cash and cash equivalents held amounted to USD 369 million as
at June 30, 2024.
16. PROVISIONS
USD Thousands
Asset
retirement
obligation
Farm-in
obligation
Pension
obligation Other Total
January 1, 2024 253,949 2,176 551 2,078 258,754
Additions – – – 195 195
Unwinding of asset retirement obligation discount 7,259 – – – 7,259
Payments (2,363) – – (504) (2,867)
Change in estimates 582 – – – 582
Reclassification 1 1,013 – – – 1,013
Currency translation adjustments (5,856) (55) – (20) (5,931)
June 30, 2024 254,584 2,121 551 1,749 259,005
Non-current 248,726 1,062 551 1,749 252,088
Current 5,858 1,059 – – 6,917
Total 254,584 2,121 551 1,749 259,005
1 The reclassification of the asset retirement obligation related to the 2024 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 9).
USD Thousands
Asset
retirement
obligation
Farm-in
obligation
Pension
obligation Other Total
January 1, 2023 206,249 3,404 306 1,478 211,437
Acquisitions 29,885 – – – 29,885
Additions – – 446 938 1,384
Unwinding of asset retirement obligation discount 13,408 – – – 13,408
Disposals 1 (2,483) – – – (2,483)
Changes in estimates 9,973 – 679 – 10,652
Payments (8,118) (1,081) (925) (364) (10,488)
Other 2 (1,272) – – – (1,272)
Reclassification 3 1,781 – – – 1,781
Currency translation adjustments 4,526 (147) 45 26 4,450
December 31, 2023 253,949 2,176 551 2,078 258,754
Non-current 246,396 1,632 551 2,078 250,657
Current 7,553 544 – – 8,097
Total 253,949 2,176 551 2,078 258,754
1 In Canada, includes the disposal of non-core properties in the John Lake area.
2 Includes accelerated decommissioning activities funded by a non cash site rehabilitation program.
3 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 9).
The farm-in obligation relates to future payments for historic costs on the Bertam field in Malaysia payable for every 1 MMboe
gross that the field produces above 10 MMboe gross and is capped at cumulative production of 27.5 MMboe gross.
In calculating the present value of the asset retirement obligation provision, a blended rate of 6% (2023: 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, 2024 and 2023, UNAUDITED
===== SIDA 18 =====
18
17. TRADE AND OTHER PAYABLES
USD Thousands June 30, 2024 December 31, 2023
Trade payables 22,107 42,761
Joint operations creditors 9,456 22,257
Accrued expenses 119,925 118,912
Other 3,798 4,941
155,286 188,871
18. FINANCIAL ASSETS AND LIABILITIES
Financial assets and liabilities by category
The accounting policies for financial instruments have been applied to the line items below:
June 30, 2024
USD Thousands
Total
Financial assets
at amortized
cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Other assets1 40,895 40,895 – –
Derivative instruments 5,921 – – 5,921
Joint operation debtors 1,578 1,578 – –
Other current receivables2 106,139 100,062 6,077 –
Cash and cash equivalents 368,797 368,797 – –
Financial assets 523,330 511,332 6,077 5,921
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
June 30, 2024
USD Thousands
Total
Financial
liabilities at
amortized cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Non-current financial liabilities 440,965 440,965 – –
Current financial liabilities 3,491 3,491 – –
Derivative instruments 6,974 – – 6,974
Joint operation creditors 9,456 9,456 – –
Other current liabilities 150,977 150,977 – –
Financial liabilities 611,863 604,889 – 6,974
December 31, 2023
USD Thousands
Total
Financial assets
at amortized
cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Other assets1 41,332 41,332 – –
Derivative instruments 42,553 – – 42,553
Joint operation debtors 910 910 – –
Other current receivables2 104,315 103,286 1,029 –
Cash and cash equivalents 517,074 517,074 – –
Financial assets 706,184 662,602 1,029 42,553
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
===== SIDA 19 =====
19
December 31, 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 440,483 440,483 – –
Current financial liabilities 3,589 3,589 – –
Derivative instruments 1,530 – – 1,530
Joint operation creditors 22,257 22,257 – –
Other current liabilities 166,869 166,869 – –
Financial liabilities 634,728 633,198 – 1,530
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
The carrying amount of the Group’s financial assets and liabilities approximate their fair values at the balance sheet dates.
For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
– Level 1: based on quoted prices in active markets;
– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
– Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
June 30, 2024
USD Thousands Level 1 Level 2 Level 3
Other current receivables 6,077 – –
Derivative instruments – current – 5,419 –
Derivative instruments – non-current – 502 –
Financial assets 6,077 5,921 –
Derivative instruments – current – 5,854 10
Derivative instruments – non-current – – 1,110
Financial liabilities – 5,854 1,120
December 31, 2023
USD Thousands Level 1 Level 2 Level 3
Other current receivables 1,029 – –
Derivative instruments – current – 35,504 –
Derivative instruments – non-current – 7,049 –
Financial assets 1,029 42,553 –
Derivative instruments – current – 1,267 –
Derivative instruments – non-current – 61 202
Financial liabilities – 1,328 202
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
===== SIDA 20 =====
20
The Group had oil price sale financial hedges outstanding as at June 30, 2024 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
July 1, 2024 - December 31, 2024 17,700 WTI/WCS Differential USD -15.03/bbl
July 1, 2024 - December 31, 2024 12,250 WTI Sale Swap USD 80.26/bbl
July 1, 2024 - December 31, 2024 3,000 Brent Sale Swap USD 85.50/bbl
The Group had electricity financial hedges outstanding as at June 30, 2024 which are summarized as follows:
Period Volume (MWh) Type Average Pricing
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
The Group had no gas price sale financial hedges outstanding as at June 30, 2024.
In 2023, IPC entered into foreign currency hedges in Canada to buy CAD 20 million per month at CAD 1.36 (sell USD) and
in Malaysia to buy MYR 11.5 million per month at MYR 4.63 (sell USD) in respect of 2024, and to buy CAD 15 million per month at
CAD 1.36 (sell USD) in respect of 2025, to partially meet forecast operational expenses in those countries. In April 2024, IPC entered
into currency hedge swaps from May 2024 to December 2024 to buy EUR 2.5 million per month, sell USD at an average exchange
rate of 1.0705. In respect of the forecast Blackrod development capital expenditure in Canada, IPC entered into further currency
hedges to purchase a total CAD 656 million for the period January 2024 to December 2025 at an average rate of CAD 1.33 (sell USD).
All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
19. CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In the normal course of business, the Group has committed to certain payments which are not recognised as liabilities. The
following table summarizes the Group’s commitments in Canada as at June 30, 2024:
CAD Millions 2024 2025 2026 2027 2028 Thereafter
Transportation service 1 14.0 33.3 60.6 89.2 92.8 1,488.2
Power2 6.2 12.4 12.4 12.4 9.8 –
Total commitments 20.2 45.7 73.0 101.6 102.6 1,488.2
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2045.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from July 1, 2024 to December 31,
2028 and an additional 5MWh at a weighted average price of CAD 58.31/MWh from July 1, 2024 to December 31, 2027.
20. RELATED PARTIES
During the six months ended June 30, 2024, the Group paid USD 222 thousand to the Lundin Foundation in respect of
sustainability advisory services provided to the Group and USD 193 thousand to Orrön Energy AB in respect of office space rental.
During the six months ended June 30, 2024, Orrön Energy AB and ShaMaran Petroleum Corp. paid respectively USD 346 thousand
and USD 95 thousand to the Group in respect of support services provided during the first six months of 2024.
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.
21. SUBSEQUENT EVENTS
In July 2024, the Group entered into the following gas price sale financial hedges in Canada:
Period Volume (Gigajoules (GJ) per
day) Type Average Pricing
August 1, 2024 - December 31, 2024 15,000 AECO Swap CAD 1.515/GJ
No other events have occurred since June 30, 2024, that are expected to have a substantial effect on this report.
Notes to the Interim Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2024 and 2023, UNAUDITED
===== SIDA 21 =====
Corporate Office
International Petroleum Corp
Suite 2800
1055 Dunsmuir Street
Vancouver, British Columbia
V7X 1L2, Canada
Tel: +1 604 689 7842
E-mail: info@international-petroleum.com
Web: international-petroleum.com□
===== SIDA 22 =====
Q2
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three and six months ended June 30, 2024
===== SIDA 23 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Contents
Non-IFRS Measures
References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA),
“operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under IFRS Accounting Standards (IFRS) and do not have any
standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF , FCF , EBITDA, operating costs and net debt/net cash that may
be used by other public companies. Management believes that OCF , FCF , EBITDA, operating costs and net debt/net cash are useful supplemental measures that may
assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Non-IFRS measures should not be
considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-IFRS measure is presented in this
MD&A. See “Non-IFRS Measures” on page 19.
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 24.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada are effective as of December
31, 2023, 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, 2023, 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, 2023, 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, 2023, price forecasts.
Certain abbreviations and technical terms used in this MD&A are defined or described under the heading “Other Supplementary Information”.
INTRODUCTION 3
HIGHLIGHTS 4
OPERATIONS REVIEW 5
• Business Overview 5
• Operations Overview 7
FINANCIAL REVIEW 10
• Financial Results 10
• Capital Expenditure 18
• Financial Position and Liquidity 18
• Non-IFRS Measures 19
• Off-Balance Sheet Arrangements 21
• Outstanding Share Data 21
• Contractual Obligations and Commitments 21
• Critical Accounting Policies and Estimates 22
• Transactions with Related Parties 22
• Financial Risk Management 22
RISK FACTORS 23
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING 23
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 24
RESERVES AND RESOURCES ADVISORY 26
OTHER SUPPLEMENTARY INFORMATION 28
2
===== SIDA 24 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
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 July 30, 2024 and is intended to provide an overview of the Group’s
operations, financial performance and current and future business opportunities. This MD&A should be read in conjunction with
IPC’s unaudited interim condensed consolidated financial statement for the three and six months ended June 30, 2024 as well
as the audited consolidated financial statements and accompanying notes for the year ended December 31, 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 3500, 1133 Melville Street, Vancouver, BC V6E 4E5, Canada and its business address is
Suite 2800, 1055 Dunsmuir Street, Vancouver, BC V7X 1L2, Canada.
Basis of Preparation
The MD&A and the Financial Statements have been prepared in accordance with International Accounting Standard 34, Interim
Financial Reporting (“IAS 34”) using accounting policies consistent with IFRS Accounting Standards (“IFRS”) as issued by the
International Accounting Standards Board (“IASB”).
Financial information is presented in United States Dollars (“USD”). However, as the Group operates in Europe and in Canada,
certain financial information prepared by subsidiaries has been reported in Euros (“EUR”) and in Canadian Dollars (“CAD”). In
addition, certain costs relating to the operations in Malaysia, which are reported in USD, are incurred in Malaysian Ringgit (“MYR”).
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
Six months ended
June 30, 2024
Six months ended
June 30, 2023
Twelve months ended
December 31, 2023
Average Period end Average Period end Average Period end
1 EUR equals USD 1.0812 1.0705 1.0811 1.0866 1.0816 1.1050
1 USD equals CAD 1.3583 1.3704 1.3477 1.3266 1.3496 1.3251
1 USD equals MYR 4.7270 4.7175 4.4564 4.6675 4.5598 4.5950
IPC completed the acquisition of Cor4 Oil Corp. (“Cor4”) on March 3, 2023. In accordance with IFRS, the Financial Statements for
periods in 2023 have been prepared on that basis, with revenues and expenses related to the Brooks assets acquired in the Cor4
acquisition included in the Financial Statements from March 3, 2023. Certain 2023 operational and financial information included
in the MD&A, including production, operating costs, OCF , FCF and EBITDA related to the Brooks 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 25 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
HIGHLIGHTS
Q2 2024 Business Highlights
• Average net production of approximately 48,400 boepd for Q2 2024 was in line with the guidance range for the period (50%
heavy crude oil, 17% light and medium crude oil and 33% natural gas).(1)
• Progressing development activities on Phase 1 of the Blackrod project which remains on schedule and on budget.
• 2.2 million IPC common shares purchased and cancelled during Q2 2024 under IPC’s normal course issuer bid (NCIB) and
continuing with target to complete the full 2023/2024 NCIB this year.
Q2 2024 Financial Highlights
• Operating costs per boe of USD 14.7 for Q2 2024, below guidance .(3)
• Operating cash flow (OCF) generation of MUSD 102 for Q2 2024, ahead of the guidance range .(3)
• Capital and decommissioning expenditures of MUSD 86 for Q2 2024, in line with guidance.
• Free cash flow (FCF) generation for Q2 2024 amounted to MUSD 8 (MUSD 75 pre-Blackrod Phase 1 project funding) .(3)
• Gross cash of MUSD 369 and net debt of MUSD 88 as at June 30, 2024. (3)
• Net result of MUSD 45 for Q2 2024.
Reserves and Resources
• Total 2P reserves as at December 31, 2023 of 468 MMboe, with a reserves life index (RLI) of 27 years. (1)(2)
• Contingent resources (best estimate, unrisked) as at December 31, 2023 of 1,145 MMboe.(1)(2)
2024 Annual Guidance
• Full year 2024 average net production guidance range maintained at 46,000 to 48,000 boepd. (1)
• Full year 2024 operating costs expected to be at the low end of the guidance range of USD 18 to 19 per boe. (3)
• Full year 2024 OCF guidance estimated at between MUSD 327 and 350 (assuming Brent USD 70 to 90 per boe for the
remainder of 2024).(3)
• Full year 2024 capital and decommissioning expenditures guidance forecast maintained at MUSD 437 .
• Full year 2024 FCF guidance estimated at between MUSD -146 and -123 (assuming Brent USD 70 to 90 per boe for the
remainder of 2024), after taking into account MUSD 362 of forecast full year 2024 capital expenditures relating to the
continued development of Phase 1 of the Blackrod project.(3)
Three months ended
June 30
Six months ended
June 30
USD Thousands 2024 2023 2024 2023
Revenue 219,040 205,564 425,459 398,080
Gross profit 72,708 52,747 127,892 117,130
Net result 45,210 32,025 78,929 71,588
Operating cash flow(3) 101,941 84,372 191,242 160,272
Free cash flow(3) 7,559 16,415 (35,752) 32,674
EBITDA(3) 103,971 85,201 190,991 161,280
Net cash/(debt)(3) (88,220) 63,548 (88,220) 63,548
4
===== SIDA 26 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
OPERATIONS REVIEW
Business Overview
Market conditions for oil commodities continued to improve following the first quarter of 2024, with Brent prices averaging USD
85 per barrel in the second quarter compared to USD 83 per barrel during the first quarter. Proactive supply management by the
OPEC+ group, led by Saudi Arabia, continues to impact the balancing of the market. The OPEC decision in early June to extend
official production cuts to end 2025 and to gradually unwind some of the voluntary cuts by the end of September 2024, subject to
market conditions, signalled what may be a continued commitment to sustain higher oil prices. Global inventories have remained
largely unchanged through the second quarter, with OECD levels remaining below the five-year average, and market observers
expect a deficit in the oil market for the remainder of 2024. With tight physical markets supported by cooling global inflation, strong
crude prices are expected to persist for the second half of the year. Around 50% of IPC’s forecast 2024 oil production is hedged at
USD 80 per barrel West Texas Intermediate (WTI) or USD 85 per barrel Dated Brent through the third quarter to end 2024..
With the Trans Mountain expansion (TMX) pipeline commencing operations in the second quarter of 2024, the WTI to Western
Canadian Select (WCS) crude price differentials averaged around USD 14 per barrel, approximately USD 5 per barrel lower than
the first quarter differential average of USD 19 per barrel. Crude exports from the new TMX pipeline are ramping up off the
coast of British Columbia, with deliveries to the US West Coast and Asia creating new end destinations for Canadian heavy
oil. This, combined with some curtailed volumes in the Western Canadian Sedimentary Basin due to forest fires, are driving
tighter differential forecasts for the third quarter of 2024. Our base case market guidance for the WTI/WCS differential remains
unchanged at USD 15 per barrel for 2024. Approximately 70% of our forecast 2024 Canadian WCS production volumes are hedged
at WTI/WCS differentials of USD 15 per barrel.
Natural gas prices remained below our 2024 base case guidance of CAD 2.13 per Mcf for the second quarter. IPC’s average
realized gas price was CAD 1.2 per Mcf during the second quarter, compared to CAD 2.5 per Mcf average for the first three
months of the year. Western Canada gas storage levels sit above the five year range in anticipation for the Shell-led LNG Canada
project start-up in British Columbia. Natural gas prices are anticipated to stay supressed until the additional export capacity is on
stream from the LNG Canada project.
Second Quarter 2024 Highlights and Full Year 2024 Guidance
IPC delivered average daily production rates of 48,400 boepd for the second quarter, in line with our 2024 Capital Markets Day
(CMD) production forecast. High uptimes were achieved across all major producing assets in our portfolio during the quarter and
the business benefited from the recently drilled oil wells within our Southern Alberta assets and the new wells brought on stream
from sustaining Pad L at the Onion Lake Thermal (OLT) asset in Canada. With strong aggregate IPC production of 48,600 boepd on
average for the first half of the year, IPC is well positioned to deliver within the production guidance of 46,000 to 48,000 boepd for
the full year.(1)
Operating costs in the second quarter of 2024 were USD 14.7 per boe, lower than our guidance. The lower costs were largely
driven by lower energy input costs within our Canadian assets. In the third quarter of 2024, a two week planned maintenance
shutdown is scheduled at the OLT asset as well as a multi-day planned maintenance shutdown at the Bertam field. Full year 2024
operating costs expected to be at the low end of the guidance range of USD 18 to 19 per boe.(3)
Operating cash flow (OCF) generation for the second quarter of 2024 was USD 102 million, ahead of guidance due to lower
operating costs and stronger oil benchmark prices than forecast. Full year 2024 OCF guidance is revised to USD 327 to 350 million
(assuming Brent USD 70 to 90 per barrel for the remainder of 2024).(3)
Capital and decommissioning expenditure for the second quarter was in line with plan at USD 86 million. Our full year 2024 capital
and decommissioning expenditure guidance is unchanged at USD 437 million.
Free cash flow (FCF) generation was USD 8 million (or USD 75 million pre-Blackrod Phase 1 development funding) during the
second quarter of 2024. Full year 2024 FCF guidance is revised to USD -146 to -123 million (or USD 216 to 239 million pre-Blackrod
Phase 1 development funding) assuming Brent USD 70 to 90 per barrel.(3)
Net debt was increased during the second quarter of 2024 by approximately USD 27 million to USD 88 million, largely as a result
of funding the normal course issuer bid (NCIB) share repurchase program.(3) The gross cash position as at June 30, 2024 was USD
369 million. Furthermore, IPC’s CAD 180 million Revolving Credit Facility (RCF) maturity was extended by 12 months to May 2026.
With a robust balance sheet and strong cashflow generation from the producing assets, IPC is strongly positioned to deliver on our
three strategic pillars of organic growth, shareholder returns and pursue value adding M&A.
5
===== SIDA 27 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Blackrod Phase 1 Project
The Blackrod asset is 100% owned by IPC and hosts the largest booked reserves and contingent resources within the IPC
portfolio. After greater than a decade of pilot operations, subsurface delineation and commercial engineering studies, IPC
sanctioned the Phase 1 development in the first quarter of 2023. The Phase 1 development targets 218 MMboe of 2P reserves,
out of the 1.28 billion boe of full field 2P reserves and best estimate contingent resources, with a multi-year forecast capital
expenditure of USD 850 million to first oil planned in late 2026. The Phase 1 development is planned for plateau production of
30,000 bopd which is expected by early 2028. As at January 1, 2024, the net present value (NPV10) of the Blackrod Phase 1
development is USD 981 million and Phase 1 has an estimated WTI breakeven price of less than USD 55 per barrel.(1)(2)
2024 marks a peak investment year at the Blackrod Phase 1 project for IPC, with USD 362 million planned to be spent in the year.
Project progress has advanced according to plan, with approximately USD 163 million spent through the first half of 2024. All major
third party contracts have been executed, including but not limited to, engineering procurement construction (EPC) agreements
for the central processing facility (CPF), well pad facilities, midstream agreements for the input fuel gas, diluent and oil blend
pipelines, drilling rig and stakeholder agreements. All major long lead items have been procured and pre-operations onboarding is
under way as the asset undergoes rapid change from a pilot steam assisted gravity drainage (SAGD) operation to a commercial
SAGD operation. It is IPC’s core operational philosophy to responsibly develop and commission projects with staff that are going to
manage and operate the asset to ensure the transition from development to operations is seamless.
As at the end of the second quarter of 2024, just under half of the Blackrod Phase 1 development capital had been spent since
the project sanction in early 2023. All major work streams have progressed as planned and the focus remains on executing to the
detailed sequencing of events as facility modules are safely delivered and installed at site. The total Phase 1 project guidance
of USD 850 million capital expenditure to first oil in late 2026 is unchanged. IPC intends to fund the remaining Blackrod Phase 1
development costs with forecast cash flow generated by its operations and cash on hand.
Stakeholder Returns: Normal Course Issuer Bid
In the fourth quarter of 2023, IPC announced the renewal of the NCIB, with the ability to repurchase up to approximately 8.3
million common shares over the period of December 5, 2023 to December 4, 2024. Under the 2023/2024 NCIB, IPC repurchased
and cancelled approximately 1.2 million common shares in December 2023 and a further 3.7 million common shares during the
first half of 2024. The average price of common shares purchased under the 2023/2024 NCIB during the first half of 2024 was SEK
126 / CAD 16 per share.
As at June 30, 2024, IPC had a total of 123,271,885 common shares issued and outstanding and IPC held no common shares
in treasury. As at July 26, 2024, IPC had a total of 123,271,885 common shares issued and outstanding and IPC held 1,027,147
common shares in treasury.
Notwithstanding the record level of capital investment forecast for 2024, IPC confirms its intention to continue to purchase and
cancel common shares under the 2023/2024 NCIB to the remaining limit as at July 1, 2024 of 3.4 million common shares by early
December 2024. This would result in the cancellation of 6.5% of shares outstanding as at the beginning of December 2023. IPC
continues to believe that reducing the number of shares outstanding while in parallel investing in material production growth at the
Blackrod project will prove to be a winning formula for our stakeholders.
Environmental, Social and Governance (ESG) Performance
Alongside the publication of our second quarter 2024 financial report, IPC releases its fifth annual Sustainability Report. The
Sustainability Report provides details on IPC’s approach to sustainability highlighting specific initiatives related to the key focus
areas set by IPC. The Sustainability Report is available on IPC’s website at www.international-petroleum.com.
During the second quarter of 2024, IPC recorded no material safety or environmental incidents.
As previously announced, IPC targets a reduction of our net GHG emissions intensity by the end of 2025 to 50% of IPC’s 2019
baseline and IPC remains on track to achieve this reduction. During the first quarter of 2024, IPC announced the commitment to
remain at 2025 levels of 20 kg CO2/boe through to the end of 2028.(4)
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, 2023 (AIF) available on IPC’s website at www.international-
petroleum.com and under IPC’s profile on SEDAR+ at www.sedarplus.ca.
(2) See “Reserves and Resources Advisory“ below. Further information with respect to IPC’s reserves, contingent resources
and estimates of future net revenue, including assumptions relating to the calculation of NPV, are described in the AIF .
(3) Non-IFRS measures, see “Non-IFRS Measures” below and in the MD&A.
(4) Emissions intensity is the ratio between oil and gas production and the associated carbon emissions, and net emissions
intensity reflects gross emissions less operational emission reductions and carbon offsets.
6
===== SIDA 28 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Operations Overview
Q2 2024 Overview
In Q2 2024, IPC continued to successfully demonstrate its commitment to operational excellence, with average daily production in
line with expectations and no material safety or environmental incidents.
In Canada, the Blackrod Phase 1 project development continues to progress in line with expectations. As at the end of Q2 2024,
process facility fabrication and critical equipment site installation is progressing in line with schedule. Site civil works continue to
advance while utility well and well Pad drilling is progressing ahead of plan. Final third party pipeline commercial agreements have
been executed as planned.
In the other assets in Canada, strong operational performance has continued through the quarter. At Ferguson three new
production wells have been brought online with encouraging initial performance. At Onion Lake Thermal, daily production
remained stable through the quarter as the new production sustaining Pad L wells are gradually phased into production. At
Suffield, performance on the oil side remains strong with three out of five of the new budgeted Ellerslie wells on production and
stable through the quarter. On the gas side, optimization activity has been slowed down with softening of the gas price. At Bertam
in Malaysia, daily production has remained strong with high production uptime and a continued focus on well rate optimization
activity to offset natural declines. In France, stable production performance continues at the major producing assets.
Reserves and Resources
The 2P reserves attributable to IPC’s oil and gas assets are 468 MMboe as at December 31, 2023, as certified by independent
third party reserve auditors. The proved plus probable reserve life index (RLI) as at December 31, 2023, is approximately 27 years.
Best estimate contingent resources as at December 31, 2023, are 1,145 MMboe (unrisked). See “Reserves and Resources
Advisory” below.
In 2024, as we embark on the peak spend year at our exciting Blackrod Phase 1 development, IPC set out a balanced base
business (non-Blackrod) capital expenditure budget for the year. IPC remains focused on organic growth and continues to mature
future development projects across all operated assets, with a significant portfolio of drilling and optimization opportunities ready
for sanction at the discretion of the Group.
Production
Average daily net production for Q2 2024 was in line with the 2024 Capital Markets Day Guidance at 48,400 boepd. In Canada,
strong operational performance has been supplemented by positive results from the recent production well drilling at the Suffield
area and Ferguson assets. In addition, our assets in Malaysia and France continued to deliver excellent results with stable
performance through the first half of 2024.
With strong operational delivery through the first half of 2024, and a strong production outlook for the remainder of the year, IPC is
well positioned to deliver annual net average daily production within the guidance range of 46,000 to 48,000 boepd.
The production during Q2 2024 with comparatives is summarized below:
Production
in Mboepd
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2024 2023 2024 2023 2023
Crude oil
Canada – Northern Assets 14.5 15.1 14.7 15.5 15.5
Canada – Southern Assets1 11.1 11.7 11.2 12.2 11.8
Malaysia 4.1 4.8 4.1 4.9 3.8
France 2.6 2.8 2.6 2.7 2.8
Total crude oil production 32.3 34.4 32.6 35.3 33.9
Gas
Canada – Northern Assets 0.5 0.4 0.4 0.4 0.4
Canada – Southern Assets 15.6 17.0 15.6 16.6 16.8
Total gas production 16.1 17.4 16.0 17.0 17.2
Total production 48.4 51.8 48.6 52.3 51.1
Quantity in MMboe 4.41 4.72 8.84 9.47 18.65
1 In respect of 2023 production, includes production from the Brooks assets acquired in the Cor4 acquisition in the Suffield area from January 1,
2023 being the effective date of the Cor4 acquisition. The acquisition of Cor4 was completed on March 3, 2023.
See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”.
7
===== SIDA 29 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
CANADA
Production
in Mboepd
Working
Interest
(WI)
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2024 2023 2024 2023 2023
- Oil Onion Lake Thermal 100% 13.0 12.9 13.2 13.1 13.3
- Oil Suffield Area1 100% 9.7 10.1 9.9 10.4 10.2
- Oil Other 50-100% 2.9 3.8 2.8 4.2 3.8
- Gas1 ~100% 16.1 17.4 16.0 17.0 17.2
Canada 41.7 44.2 41.9 44.7 44.5
1 In respect of 2023 production, includes production from the Brooks assets acquired in the Cor4 acquisition in the Suffield area from January 1,
2023 being the effective date of the Cor4 acquisition. The acquisition of Cor4 was completed on March 3, 2023.
Production
Net production from IPC’s assets in Canada during Q2 2024 was in line with guidance at 41,700 boepd. Strong operational
performance has been supplemented by positive results from the recent oil well drilling in the Suffield Ellerslie play and at the
Ferguson asset. Production remains stable at Onion Lake Thermal as we phase in the new wells from the latest production
sustaining Pad L.
Organic Growth and Capital Projects
In Canada, as the Blackrod Phase 1 project development enters its most capital intensive phase, IPC announced a reduced base
business budget set for 2024. At our Southern assets, the focus remains on the high performing Suffield Ellerslie play and is
supplemented with the next phase of development well drilling at our Ferguson asset. At Onion Lake Thermal, production rate
optimization is the priority with a continued phased ramp up of the latest production sustaining Pad L planned.
During Q2 2024, the Blackrod Phase 1 project development continues to progress in line with expectations. As at the end of Q2
2024, process facility fabrication and critical equipment site installation is progressing in line with schedule, site civil activities
continue to advance while utility well and well Pad drilling is progressing ahead of plan. In addition, the final third party pipeline
commercial agreements have been executed as planned.
As of the end of Q2 2024, the three planned wells at the Ferguson asset have been drilled and brought online with encouraging
initial performance.
At the end of Q2 2024, three out of five budgeted Suffield area Ellerslie play wells have been drilled and continue to deliver
positive results. The drilling rig is scheduled to return to the Suffield asset in Q3 2024 to complete the final two budgeted Ellerslie
play wells in the year.
At Onion Lake Thermal, daily production has remained stable with five production sustaining Pad L well pairs online. The sixth and
seventh Pad L wells are scheduled to be brought online in Q3 and Q4 2024 respectively.
MALAYSIA
Production
in Mboepd WI
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2024 2023 2024 2023 2023
Bertam 100% 4.1 4.8 4.1 4.9 3.8
Production
Net production at Bertam in Malaysia in Q2 2024 was above guidance at 4,100 boepd with high production uptime and a continued
focus on well rate optimization activity to offset natural declines.
Organic Growth and Capital Projects
In Malaysia, field development studies have progressed in line with expectations as IPC matures the remaining undeveloped
potential of the Bertam field following the successful results from the latest development drilling campaign.
8
===== SIDA 30 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
FRANCE
Production
in Mboepd WI
Three months ended
June 30
Six months ended
June 30
Year ended
December 31
2024 2023 2024 2023 2023
France
- Paris Basin 100%1 2.3 2.5 2.3 2.3 2.4
- Aquitaine 50% 0.3 0.3 0.3 0.4 0.4
2.6 2.8 2.6 2.7 2.8
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q2 2024 was in line with guidance at 2,600 boepd with stable performance at all the major
producing assets.
Organic Growth
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.
9
===== SIDA 31 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
FINANCIAL REVIEW
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q2-24 Q1-24 Q4-23 Q3-23 Q2-23 Q1-23 Q4-22 Q3-22
Revenue 219,040 206,419 198,460 257,366 205,564 192,516 254,615 299,361
Gross profit 72,708 55,184 39,955 93,429 52,747 64,383 95,411 140,489
Net result 45,210 33,719 29,710 71,681 32,025 39,563 61,183 90,503
Earnings per share – USD 0.36 0.27 0.23 0.56 0.24 0.29 0.45 0.63
Earnings per share fully
diluted – USD 0.36 0.26 0.22 0.54 0.24 0.28 0.44 0.62
Operating cash flow1 101,941 89,301 73,634 119,142 84,372 75,900 113,668 171,654
Free cash flow1 7,559 (43,311) (64,688) 34,703 16,415 16,259 65,288 116,681
EBITDA1 103,971 87,020 66,284 123,054 85,201 76,079 125,651 174,328
Net cash/(debt) at period end1 (88,220) (60,572) 58,043 83,097 63,548 66,956 175,098 88,615
1 See definition on page 19 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands June 30, 2024 December 31, 2023
Non-current assets 1,462,923 1,372,388
Current assets 525,252 690,597
Total assets 1,988,175 2,062,985
Total non-current liabilities 784,921 779,838
Current liabilities 177,035 202,888
Total liabilities 961,956 982,726
Net assets 1,026,219 1,080,259
Working capital (including cash) 348,217 487,709
10
===== SIDA 32 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Selected Interim Financial Information
The Group operates within several geographical areas. Operating segments are reported at a country level, with Canada being
further analyzed by main areas: (i) Canada – Northern Assets (comprising mainly of the Onion Lake Thermal asset) and (ii) Canada –
Southern Assets (comprising mainly of the Suffield assets, including the Brooks assets). This is consistent with the internal
reporting provided to IPC management. The following tables present certain segment information.
Three months ended June 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 115,482 75,536 39,341 17,253 – 247,612
NGLs – 275 – – – 275
Gas 44 6,631 – – – 6,675
Net sales of oil and gas 115,526 82,442 39,341 17,253 – 254,562
Change in under/over lift position – – – 2,215 – 2,215
Royalties (22,377) (11,912) – (1,161) – (35,450)
Hedging settlement (1,523) (1,121) – – – (2,644)
Other operating revenue – – – 237 120 357
Revenue 91,626 69,409 39,341 18,544 120 219,040
Operating costs (19,260) (30,541) (7,229) (7,804) – (64,834)
Cost of blending (34,876) (6,799) – – – (41,675)
Change in inventory position – (96) (4,829) 53 – (4,872)
Depletion (9,465) (13,021) (6,893) (3,282) – (32,661)
Depreciation of other assets – – (2,218) – – (2,218)
Exploration and business
development costs – – – – (72) (72)
Gross profit/(loss) 28,025 18,952 18,172 7,511 48 72,708
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
11
===== SIDA 33 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Six months ended June 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 219,627 141,007 57,894 33,970 – 452,498
NGLs – 519 – – – 519
Gas 169 20,923 – – – 21,092
Net sales of oil and gas 219,796 162,449 57,894 33,970 – 474,109
Change in under/over lift position – – – 5,131 – 5,131
Royalties (37,872) (20,900) – (2,300) – (61,072)
Hedging settlement 3,732 2,830 – – – 6,562
Other operating revenue – – – 454 275 729
Revenue 185,656 144,379 57,894 37,255 275 425,459
Operating costs (39,918) (69,772) (14,245) (16,715) – (140,650)
Cost of blending (73,170) (13,711) – – – (86,881)
Change in inventory position 368 (325) 210 152 – 405
Depletion (19,209) (26,181) (13,923) (6,501) – (65,814)
Depreciation of other assets – – (4,480) – – (4,480)
Exploration and business
development costs – – – – (147) (147)
Gross profit/(loss) 53,727 34,390 25,456 14,191 128 127,892
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.
12
===== SIDA 34 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Three and six months ended June 30, 2024, Review
Revenue
Total revenue amounted to USD 219,040 thousand for Q2 2024, compared to USD 205,564 thousand for Q2 2023 and USD
425,459 thousand for the first six months of 2024 compared to USD 398,080 thousand for the first six months of 2023 and is
analyzed as follows:
USD Thousands
Three months ended June 30 Six months ended June 30
2024 2023 2024 2023
Crude oil sales 247,612 212,271 452,498 392,804
Gas and NGL sales 6,950 15,654 21,611 36,327
Change in under/overlift position 2,215 1,823 5,131 4,493
Royalties (35,450) (25,937) (61,072) (46,076)
Hedging settlement (2,644) 1,531 6,562 10,115
Other operating revenue 357 222 729 417
Total revenue 219,040 205,564 425,459 398,080
The main components of total revenue for the three and six months ended June 30, 2024, and June 30, 2023, respectively, are
detailed below.
Crude oil sales
Three months ended June 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 115,482 75,536 39,341 17,253 247,612
- Quantity sold in bbls 1,739,097 1,119,518 421,810 203,008 3,483,433
- Average price realized USD per bbl 66.40 67.47 93.27 84.98 71.08
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
Crude oil revenue was 17% higher in Q2 2024 compared to Q2 2023 mainly due to higher oil prices.
The Suffield area assets and Onion Lake Thermal crude oil in Canada is blended with purchased condensate diluent volumes to
meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada.
The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q2 2024, WTI averaged USD 81 per bbl compared to USD 73 per bbl for Q2 2023 and the
average discount to WCS used in IPC’s pricing formula was USD 14 per bbl compared to USD 15 per bbl for Q2 2023.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There were two cargo liftings in Malaysia
during Q2 2024 and one cargo lifting in Q2 2023. Produced unsold oil barrels from Bertam at the end of Q2 2024 amounted to
169,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 85 per bbl for
Q2 2024 compared to USD 78 per bbl for the comparative period.
13
===== SIDA 35 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Six months ended June 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 219,627 141,007 57,894 33,970 452,498
- Quantity sold in bbls 3,565,871 2,246,532 624,329 404,612 6,841,344
- Average price realized USD per bbl 61.59 62.77 92.73 83.96 66.14
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
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 higher by 15% during the first six months of 2024 compared to the first six months of 2023 mainly due to
higher oil prices and more cargo liftings in Malaysia. In addition, Canadian – Southern Assets sales volumes are 5% higher in the
first six months 2024 compared to the first six months of 2023 as a result of the Brooks assets acquisition 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 2024,
WTI averaged USD 79 per bbl compared to USD 75 per bbl for the comparative period and the average discount to WCS used in
our pricing formula was USD 16 per bbl compared to USD 20 per bbl for the comparative period.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices and the average market Brent crude oil
price was USD 84 per bbl for the first six months of 2024 compared to USD 80 per bbl for the comparative period.
Gas and NGL sales
Three months ended June 30, 2024
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 44 6,906 6,950
- Quantity sold in Mcf 63,367 7,806,525 7,869,892
- Average price realized USD per Mcf 0.70 0.88 0.88
Three months ended June 30, 2023
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 63 15,591 15,654
- Quantity sold in Mcf 41,620 8,448,955 8,490,575
- Average price realized USD per Mcf 1.52 1.85 1.84
Gas and NGL sales revenue was 56% lower for Q2 2024 compared to Q2 2023 mainly due to the lower achieved gas price. IPC’s
achieved gas price is based on AECO pricing plus a premium. For Q2 2024, IPC realized an average price of CAD 1.17 per Mcf
compared to AECO average pricing of CAD 1.17 per Mcf.
14
===== SIDA 36 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Six months ended June 30, 2024
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 169 21,442 21,611
- Quantity sold in Mcf 133,858 15,475,133 15,608,991
- Average price realized USD per Mcf 1.26 1.39 1.38
Six months ended June 30, 2023
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 157 36,170 36,327
- Quantity sold in Mcf 94,669 16,094,254 16,188,923
- Average price realized USD per Mcf 1.66 2.25 2.24
Gas and NGL sales revenue was 41% lower for the first six months of 2024 compared to the first six months of 2023 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 2024, IPC realized an average price
of CAD 1.84 per Mcf compared to AECO average pricing of CAD 1.83 per Mcf.
Hedging settlement
IPC enters into risk management contracts in order to ensure a certain level of cash flow. It focuses mainly on oil and gas price
swaps to limit pricing exposure. Oil and gas pricing contracts are not entered into for speculative purposes.
The realized hedging settlement for the first six months of 2024 amounted to a gain of USD 6,562 thousand on the oil contracts
and there were no gas financial hedges. Also see the Financial Position and Liquidity and the Financial Risk Management sections
below.
Production costs
Production costs including inventory movements amounted to USD 111,381 thousand for Q2 2024 compared to USD 116,597
thousand for Q2 2023 and USD 227,126 thousand for the first six months of 2024 compared to USD 234,124 thousand for the
comparative period, and is analyzed as follows:
Three months ended June 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 19,260 30,541 11,369 7,804 (4,140) 64,834
USD/boe2 14.10 12.55 30.76 33.13 n/a 14.72
Cost of blending 34,876 6,799 – – – 41,675
Change in inventory position – 96 4,829 (53) – 4,872
Production costs 54,136 37,436 16,198 7,751 (4,140) 111,381
Three months ended June 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 23,450 41,699 11,366 7,867 (4,095) 80,287
USD/boe2 16.62 15.96 26.12 30.44 n/a 17.02
Cost of blending 35,005 5,865 – – – 40,870
Change in inventory position (802) 426 (4,747) 563 – (4,560)
Production costs 57,653 47,990 6,619 8,430 (4,095) 116,597
15
===== SIDA 37 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Six months ended June 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 39,918 69,772 22,435 16,715 (8,190) 140,650
USD/boe2 14.50 14.30 30.05 35.97 n/a 15.91
Cost of blending 73,170 13,711 – – – 86,881
Change in inventory position (368) 325 (210) (152) – (405)
Production costs 112,720 83,808 22,225 16,563 (8,190) 227,126
Six months ended June 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 48,483 76,197 23,592 15,605 (8,145) 155,732
USD/boe2 16.89 15.54 26.45 32.34 n/a 17.03
Cost of blending 75,745 12,942 – – – 88,687
Change in inventory position (341) 387 (10,619) 278 – (10,295)
Production costs 123,887 123,887 12,973 15,883 (8,145) 234,124
1 See definition on page 19 under “Non-IFRS measures”.
2 USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and for 2023, includes the
Brooks assets 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 19.56 for Q2 2024 and USD 16.71 for the comparative period and USD 19.08 and USD 17.32 for the six months
ended June 30, 2024, and June 30, 2023, respectively.
Operating costs
Operating costs amounted to USD 64,834 thousand for Q2 2024 compared to USD 80,287 thousand for Q2 2023 and USD
140,650 thousand for the first six months of 2024 compared to USD 155,732 for the first six months of 2023. Operating costs
per boe amounted to USD 14.72 per boe in Q2 2024 below guidance for the quarter and compared with USD 17.02 per boe in Q2
2023. The decrease in costs in Q2 2024 compared to Q2 2023 is due mainly to lower electricity and gas prices.
Cost of blending
For the Suffield area and Onion Lake Thermal 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 cost of the diluent amounted to USD 41,675 thousand for Q2 2024 compared to USD 40,870 thousand for Q2 2023 and USD
86,881 thousand for the first six months of 2024 compared to USD 88,687 for the comparative period.
Change in inventory position
The Bertam field in Malaysia is located offshore and production is lifted and sold from the FPSO Bertam when a cargo parcel size
is reached. Accordingly, the timing of a lifting varies based on the inventory level on the FPSO facility and the change in inventory
position varies, both positively and negatively, from period to period. Inventories are valued at the lower of cost including depletion,
and market value, and the difference in the valuation between period ends is reflected in the change in inventory position in the
statement of operations. At the end of Q2 2024, IPC had crude entitlement of 169,000 barrels of oil on the FPSO Bertam facility
being crude produced but not yet sold. Two crude cargos were lifted from Bertam in April and June 2024 with the next lifting in
August 2024.
Depletion and decommissioning costs
The total depletion of oil and gas properties amounted to USD 32,661 thousand for Q2 2024 compared to USD 33,362 thousand
for Q2 2023 (including an adjustment for accelerated decommissioning activities amounting to USD 24,178 thousand) and USD
65,814 thousand for the first six months of 2024 compared to USD 39,801 thousand for the first six months of 2023 (including an
adjustment for accelerated decommissioning activities amounting to USD 24,123 thousand).
16
===== SIDA 38 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
The depletion charge is analyzed in the following tables:
Three months ended June 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,465 13,021 6,893 3,282 32,661
USD per boe2 6.93 5.35 18.65 13.93 7.41
Three months ended June 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,222 14,993 5,551 3,596 33,362
USD per boe2 6.53 5.74 12.76 13.92 7.07
Six months ended June 30, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 19,209 26,181 13,923 6,501 65,814
USD per boe2 6.98 5.37 18.65 13.99 7.44
Six months ended June 30, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands1 18,548 27,267 11,380 6,729 63,924
USD per boe2 6.46 5.69 12.76 13.94 7.01
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 for 2023,
includes the Brooks assets 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 increased compared to the prior year following the capitalization of the workover costs
incurred in Q4 2023 and 2024.
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 2,218 thousand for Q2 2024 compared to USD 2,436 thousand for Q2
2023 and USD 4,480 thousand for the first six months of 2024 compared to USD 4,994 thousand for the first six months of 2023.
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 the PSC extension to 2035.
Exploration and business development costs
The total exploration and business developments costs amounted to a cost of USD 147 thousand for the first six months of 2024
and USD 2,031 thousand for the first six months of 2023 which included the Brooks assets acquisition related costs amounting to
USD 831 thousand.
Net financial items
Net financial items amounted to a charge of USD 10,048 thousand for Q2 2024, compared to a charge of USD 6,955 thousand for
Q2 2023 and a charge of USD 19,818 thousand for the first six months of 2024 compared to a charge of USD 11,970 thousand for
the first six months of 2023, and included a non-cash net foreign exchange loss of USD 3,617 thousand for the first six months
of 2024 compared to a net foreign exchange loss of USD 2,347 thousand for the first six months of 2023. The foreign exchange
movements 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 8,492 thousand for Q2 2024,
compared to USD 5,464 thousand for Q2 2023 and a charge of USD 16,201 thousand for the first six months of 2024 compared to
a charge of 9,623 thousand for the comparative period.
17
===== SIDA 39 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
The interest expense amounted to USD 8,928 thousand for Q2 2024, compared to USD 5,455 thousand for the comparative period
in 2023 and USD 17,746 thousand for the first six months of 2024 compared to USD 10,804 thousand for the first six months of
2023 and mainly related to the bond interest at a coupon rate of 7.25% per annum. The increase compared to the comparative
period is largely attributable to the additional MUSD 150 bond tap issue completed in Q3 2023. Interest income generated on cash
balances held amounted to USD 4,917 thousand for Q2 2024 and USD 10,534 thousand for the first six months of 2024 and is
higher than the comparative period of USD 4,335 thousand for Q2 2023 and USD 9,259 thousand for the first six months of 2023
due mainly to higher interest rates.
The unwinding of the asset retirement obligation discount rate amounted to USD 3,641 thousand for Q2 2024, compared to USD
3,474 thousand for the comparative period and USD 7,259 thousand for the first six months of 2024 compared to USD 6,542
thousand for the first six months of 2023 and has increased mainly as a result of the inclusion of the Brooks assets acquired in
March 2023.
Income tax
The corporate income tax amounted to a charge of USD 13,470 thousand for Q2 2024, compared to a charge of USD 9,609
thousand for the comparative period and a charge of USD 21,216 thousand for the first six months of 2024 compared to a charge
of USD 25,220 for the comparative period.
The current income tax charge amounted to USD 5,718 thousand for Q2 2024 and USD 7,091 thousand during the first six
months of 2024 and mainly related to France and Malaysia. No corporate income tax is expected to be payable in Canada in 2024
due to the usage of historical tax pools.
Capital Expenditure
Development and exploration and evaluation expenditure incurred during the first six months of 2024 was as follows:
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 170,280 21,632 15,003 1,812 208,727
Exploration and evaluation 147 – 483 – 630
170,427 21,632 15,486 1,812 209,357
Capital expenditure of USD 208,727 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project, drilling
on the Ferguson and Brooks assets and in Malaysia on the well workovers.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 20,877 thousand as at June 30, 2024, which included USD 19,250 thousand in
respect of the FPSO Bertam. The FPSO Bertam is being depreciated on a unit of production basis based to August 2025, being the
original Bertam field PSC expiry date before the PSC extension to 2035.
Financial Position and Liquidity
Financing
As at January 2023, IPC had MUSD 300 of bonds outstanding, issued in February 2022 and maturing in February 2027 with a fixed
coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group also had a revolving
credit facility of MCAD 75 (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In Q3 2023, IPC completed a tap issue of MUSD 150 under IPC’s existing 7.25% bond framework issued at 7% discount to par
value with proceeds amounting to MUSD 139.5 before transaction costs. For accounting purposes, the discounted amount was
recognised in the balance sheet and the discount will be unwound over the period to maturity of the bond and charged to the
interest expense line of the Statement of Operations using the effective interest rate methodology. As at June 30, 2024, IPC had a
nominal MUSD 450 of bonds outstanding with maturity in February 2027. The bond repayment obligations as at June 30, 2024, are
classified as non-current as there are no mandatory repayments within the next twelve months.
During 2023, the Group increased the Canadian RCF from MCAD 75 to MCAD 180 and extended the maturity to May 2025. During
Q2 2024, the Group extended the maturity of the Canadian RCF to May 2026. As at June 30, 2024, operational letters of credit in
an aggregate of MCAD 40.2 have been issued under the Canadian RCF , including letters of credit issued in June 2024 for a total
amount of MCAD 35 to support the third party pipeline construction agreements for the Blackrod project during 2024 and 2025.
As at June 30, 2024, IPC had an unsecured Euro credit facility in France (the “France Facility“), with maturity in May 2026. IPC
makes quarterly repayments of the French Facility and the amount remaining outstanding under the France Facility as at June
30, 2024 was MUSD 7. An amount of MUSD 3.5 drawn under the France Facility as at June 30, 2024 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, 2024.
18
===== SIDA 40 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Total net debt as at June 30, 2024 amounted to MUSD 88. Cash and cash equivalents held amounted to MUSD 369 as at June 30,
2024.
IPC intends to fund the remaining Blackrod Phase 1 project development costs with cash on hand and forecast FCF generated by
its operations.
Working Capital
As at June 30, 2024, the Group had a working capital balance including cash of USD 348,217 thousand compared to USD 487,709
thousand as at December 31, 2023. The difference as at June 30, 2024, from December 31, 2023 is mainly as a result of the
decreased cash following capital expenditures on the Blackrod Phase 1 development project and the continuing NCIB program.
Non-IFRS Measures
In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free
cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do
not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by
other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in
accordance with IFRS.
The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by and
the financial performance and condition of the Corporation. Management also uses non-IFRS measures internally in order to
facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s
ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures
are important supplemental measures of operating performance because they highlight trends in the core business that may
not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for
assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable
between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties
frequently use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the
purpose of presenting information about management’s current expectations and plans relating to the future and readers are
cautioned that such statements may not be appropriate for other purposes.
“Operating cash flow” is calculated as revenue less production costs 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
2024 2023 2024 2023
Revenue 219,040 205,564 425,459 398,080
Production costs (111,381) (116,597) (227,126) (234,124)
Current tax (5,718) (4,595) (7,091) (8,586)
Operating cash flow 101,941 84,372 191,242 155,370
The operating cash flow for the six months ended June 30, 2023 including the operating cash flow contribution of the Brooks
assets acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 160,272
thousand.
19
===== SIDA 41 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
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
2024 2023 2024 2023
Operating cash flow - see above 101,941 84,372 191,242 155,370
Capital expenditures (84,101) (58,822) (209,357) (107,060)
Abandonment and farm-in expenditures1 (2,241) (3,717) (2,363) (4,928)
General, administration and depreciation expenses before
depreciation2 (3,689) (3,766) (7,342) (7,577)
Cash financial items3 (4,351) (1,652) (7,932) (2,300)
Free cash flow 7,559 16,415 (35,752) 33,505
1 See note 16 to the Financial Statements
2 Depreciation is not specifically disclosed in the Financial Statements
3 See notes 4 and 5 to the Financial Statements.
The free cash flow for the six months ended June 30, 2023 including the free cash flow contribution of the Brooks assets
acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted 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
2024 2023 2024 2023
Net result 45,210 32,025 78,929 71,588
Net financial items 10,048 6,955 19,818 11,970
Income tax 13,470 9,609 21,216 25,220
Depletion and decommissioning costs 32,661 33,362 65,814 39,801
Depreciation of other tangible fixed assets 2,218 2,436 4,480 4,994
Exploration and business development costs 72 422 147 2,031
Depreciation included in general, administration and depreciation
expenses1 292 392 587 775
EBITDA 103,971 85,201 190,991 156,379
1 Item is not shown in the Financial Statements.
The EBITDA for the six months ended June 30, 2023 including the EBITDA contribution of the Brooks assets acquisition from the
effective date of January 1, 2023 to the completion date of March 3, 2023 amounted 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
2024 2023 2024 2023
Production costs 111,381 116,597 227,126 234,124
Cost of blending (41,675) (40,870) (86,881) (88,687)
Change in inventory position (4,872) 4,560 405 10,295
Operating costs 64,834 80,287 140,650 155,732
The operating costs for the six months ended June 30, 2023 including the operating costs contribution of the Brooks assets
acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 162,533
thousand.
20
===== SIDA 42 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
Net cash/(debt)
The following table sets out how net cash/(debt) is calculated:
USD Thousands June 30, 2024 December 31, 2023
Bank loans (7,017) (9,031)
Bonds1 (450,000) (450,000)
Cash and cash equivalents 368,797 517,074
Net cash/(debt) (88,220) 58,043
1 The bond amount represents the redeemable value at maturity (February 2027).
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, has issued six letters of credit as follows: (a) MCAD 2.6 in respect of its obligations to
purchase diluent; (b) MCAD 0.9 in respect of its obligations related to the Ferguson asset, increasing by MCAD 0.1 annually to a
maximum of MCAD 1.0; (c) MCAD 1.3 in respect of pipeline access; (d) MCAD 0.5 in relation to the hedging of electricity prices;
(e) and (f) MCAD 24.5 and MCAD 10.5 respectively in respect of its obligations related to Blackrod pipelines.
Outstanding Share Data
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2023, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in
treasury.
Over the period of January 1, 2023 to December 4, 2023, IPC purchased and cancelled a total of 8,603,179 common shares
under the normal course issuer bid/share repurchase program (NCIB). The NCIB was renewed in Q4 2023 and IPC is entitled to
purchase up to 8,342,119 common shares over the period of December 5, 2023 to December 4, 2024. During December 2023,
IPC purchased and cancelled a total of 1,232,754 common shares under the renewed NCIB. As at December 31, 2023, IPC had a
total of 126,992,066 common shares issued and outstanding, with no common shares held in treasury.
Over the period of January 1, 2024 to June 30, 2024, IPC purchased and cancelled a total of 3,720,181 common shares under the
NCIB. As at June 30, 2024, IPC had a total of 123,271,885 common shares issued and outstanding, with no common shares in
treasury.
Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 40,697,533
common shares in IPC, representing 32.4% of the outstanding common shares as at June 30, 2024.
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 3,331,707 IPC Share Unit Plan awards outstanding as at July 30, 2024 (4,333 awards granted in January 2022, 1,090,091
awards granted in March 2022, 2,391 awards granted in July 2022, 2,072 awards granted in January 2023, 1,033,326 awards
granted in February 2023, 3,244 awards granted in July 2023, 2,443 awards granted in January 2024, 1,189,479 awards granted in
February 2024 and 4,328 awards granted in July 2024).
Contractual Obligations and Commitments
In the normal course of business, the Group has committed to certain payments which are not recognised as liabilities. The
following table summarizes the Group’s commitments in Canada as at June 30, 2024:
MCAD 2024 2025 2026 2027 2028 Thereafter
Transportation service 1 14.0 33.3 60.6 89.2 92.8 1,488.2
Power2 6.2 12.4 12.4 12.4 9.8 –
Total commitments 20.2 45.7 73.0 101.6 102.6 1,488.2
1 IPC has firm transportation commitments on oil and natural gas pipelines that expire between 2037 and 2045.
2 IPC has physical delivery power hedges to purchase 15MWh at a weighted average price of CAD 74.92/MWh from July 1, 2024 to December 31,
2028 and an additional 5MWh at a weighted average price of CAD 58.31/MWh from July 1, 2024 to December 31, 2027.
21
===== SIDA 43 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
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 the six months ended June 30, 2024, the Group paid USD 222 thousand to the Lundin Foundation in respect of
sustainability advisory services provided to the Group and USD 193 thousand to Orrön Energy AB in respect of office space rental.
During the six months ended June 30, 2024, Orrön Energy AB and ShaMaran Petroleum Corp. paid respectively USD 346
thousand and USD 95 thousand to the Group in respect of support services provided during the first six months of 2024.
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, 2024, the Corporation had entered into oil 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 oil price sale financial hedges outstanding as at June 30, 2024, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
July 1, 2024 – December 31, 2024 17,700 WTI/WCS Differential USD -15.03/bbl
July 1, 2024 – December 31, 2024 12,250 WTI Sale Swap USD 80.26/bbl
July 1, 2024 – December 31, 2024 3,000 Brent Sale Swap USD 85.50/bbl
22
===== SIDA 44 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
The Group had electricity financial hedges outstanding as at June 30, 2024, which are summarized as follows:
Period Volume (MWh) Type Average Pricing
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
The Group had no gas price sale financial hedges outstanding as at June 30, 2024.
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 3,770 thousand as at June 30, 2024.
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 2023, IPC entered into foreign currency hedges in Canada to buy CAD 20 million per month at CAD 1.36 (sell USD) and
in Malaysia to buy MYR 11.5 million per month at MYR 4.63 (sell USD) in respect of 2024, and to buy CAD 15 million per month at
CAD 1.36 (sell USD) in respect of 2025, to partially meet forecast operational expenses in those countries. In April 2024, IPC entered
into currency hedge swaps from May 2024 to December 2024 to buy EUR 2.5 million per month, sell USD at an average exchange
rate of 1.0705. In respect of the forecast Blackrod development capital expenditure in Canada, IPC entered into further currency
hedges to purchase a total CAD 656 million for the period January 2024 to December 2025 at an average rate of CAD 1.33 (sell USD).
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had
a negative fair value of USD 4,823 thousand as at June 30, 2024.
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 FACTORS
IPC is engaged in the exploration, development and production of oil and gas and is exposed to various operational, environmental,
market and financial risks and uncertainties. For further information and discussion of these risks and uncertainties, please see
IPC’s Annual Information Form for the year ended December 31, 2023 (”AIF”) available on SEDAR+ at www.sedarplus.ca or on
IPC’s website at www.international-petroleum.com. See also “Cautionary Statement Regarding Forward Looking Information” and
“Reserves and Resources Advisory” in this MD&A.
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be
disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation
is recorded, processed, summarized and reported within the time periods specified in the securities legislation. Management,
under the supervision of the Chief Executive Officer and the Chief Financial Officer, is responsible for the design and operation of
disclosure controls and procedures.
Internal Controls over Financial Reporting
Management is also responsible for the design of the Group’s internal controls over financial reporting in order to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with IFRS. However, due to inherent limitations, internal control over financial reporting may not prevent or detect all
misstatements and fraud.
There have been no material changes to the Groups internal control over financial reporting during the six months period ended June
30, 2024, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial reporting.
23
===== SIDA 45 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
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:
• 2024 production ranges (including total daily average production), production composition, cash flows, operating costs and
capital and decommissioning expenditure estimates;
• Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business
plans and assumptions regarding the business environment, which are subject to change;
• IPC’s financial and operational flexibility to continue to react to recent events and navigate the Corporation through periods of
volatile commodity prices;
• The ability to fully fund future expenditures from cash flows and current borrowing capacity;
• IPC’s intention and ability to continue to implement strategies to build long-term shareholder value;
• The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth;
• The continued facility uptime and reservoir performance in IPC’s areas of operation;
• Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing,
regulatory approvals, third party commercial arrangements, breakeven oil prices and net present values;
• Future development potential of the Suffield, Brooks, Ferguson and Mooney operations, including the timing and success of
future oil and gas drilling and optimization programs;
• Current and future operations and production performance at Onion Lake Thermal;
• The potential improvement in the Canadian oil egress situation and IPC’s ability to benefit from any such improvements;
• The ability to maintain current and forecast production in France and Malaysia;
• The intention and ability of IPC to acquire further common shares under the NCIB, including the timing of any such purchases;
• The return of value to IPC’s shareholders as a result of the NCIB;
• The ability of IPC to implement further shareholder distributions in addition to the NCIB;
• IPC’s ability to implement its greenhouse gas (GHG) emissions intensity and climate strategies and to achieve its net GHG
emissions intensity reduction targets;
• IPC’s ability to implement projects to reduce net emissions intensity, including potential carbon capture and storage;
• Estimates of reserves and contingent resources;
• The ability to generate free cash flows and use that cash to repay debt;
• IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the
Corporation;
• IPC’s ability to 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 ability to identify and complete future acquisitions;
• Expectations regarding the oil and gas industry in Canada, Malaysia and France, including assumptions regarding future
royalty rates, regulatory approvals, legislative changes, and ongoing projects and their expected completion; and
• Future drilling and other exploration and development activities.
Statements relating to “reserves“ and “contingent resources“ are also deemed to be forward-looking statements, as they involve
the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the
quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery
of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of
management. See also “Reserves and Resources Advisory“.
24
===== SIDA 46 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
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; our ability to maintain
our existing credit ratings; our ability to achieve our performance targets; the timing of receipt of regulatory approvals; the
performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures;
the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling
operations; the successful completion of acquisitions and dispositions and that we will be able to implement our standards,
controls, procedures and policies in respect of any acquisitions and realize the expected synergies on the anticipated timeline or at
all; the benefits of acquisitions; the state of the economy and the exploration and production business in the jurisdictions in which
IPC operates and globally; the availability and cost of financing, labour and services; our intention to complete share repurchases
under our normal course issuer bid program, including the funding of such share repurchases, existing and future market
conditions, including with respect to the price of our common shares, and compliance with respect to applicable limitations under
securities laws and regulations and stock exchange policies; and the ability to market crude oil, natural gas and natural gas liquids
successfully.
Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are reasonable,
undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they will prove to
be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks
and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks.
These include, but are not limited to:
• General global economic, market and business conditions;
• The risks associated with the oil and gas industry in general such as operational risks in development, exploration and
production;
• Delays or changes in plans with respect to exploration or development projects or capital expenditures;
• The uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses;
• Health, safety and environmental risks;
• Commodity price fluctuations;
• Interest rate and exchange rate fluctuations;
• Marketing and transportation;
• Loss of markets;
• Environmental and climate-related risks;
• Competition;
• Innovation and cybersecurity risks related to our systems, including our costs of addressing or mitigating such risks;
• The ability to attract, engage and retain skilled employees
• Incorrect assessment of the value of acquisitions;
• Failure to complete or realize the anticipated benefits of acquisitions or dispositions;
• The ability to access sufficient capital from internal and external sources;
• Failure to obtain required regulatory and other approvals;
• Geopolitical conflicts, including the war between Ukraine and Russia and the conflict in the Middle East, and their potential
impact on, among other things, global market conditions; and
• Changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations.
Readers are cautioned that the foregoing list of factors is not exhaustive. See also “Risk Factors”
Estimated FCF generation is based on IPC’s current business plans over the periods of 2024 to 2028 and 2029 to 2033.
Assumptions include average net production of approximately 55 Mboepd over the period of 2024 to 2028, average net production
of approximately 65 Mboepd over the period of 2029 to 2033, 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, 2023, (See “Cautionary
Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk Factors”) and other reports
on file with applicable securities regulatory authorities, including previous financial reports, management’s discussion and analysis
and material change reports, which may be accessed through the SEDAR+ website (www.sedarplus.ca) or IPC’s website (www.
international-petroleum.com).
Management of IPC approved the production, operating costs, operating cash flow, capital and decommissioning expenditures
and free cash flow guidance and estimates contained herein as of the date of this MD&A. The purpose of these guidance and
estimates is to assist readers in understanding IPC’s expected and targeted financial results, and this information may not be
appropriate for other purposes.
25
===== SIDA 47 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
RESERVES AND RESOURCES ADVISORY
This MD&A contains references to estimates of gross and net reserves and resources attributed to the Corporation’s oil and gas
assets. Gross reserves/resources are the working interest (operating or non-operating) share before deduction of royalties and
without including any royalty interests. Net reserves/resources are the working interest (operating or non-operating) share after
deduction of royalty obligations, plus royalty interests in reserves/resources, and in respect of PSCs in Malaysia, adjusted for cost
and profit oil. Unless otherwise indicated, reserves/resource volumes are presented on a gross basis.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in
Canada are effective as of December 31, 2023, 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, 2023 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, 2023, 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, 2023 price forecasts.
The price forecasts used in the Sproule and ERCE reports, are available on the website of Sproule (sproule. com) and are contained
in the AIF . These price forecasts are as at December 31, 2023 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 468 MMboe as at December 31, 2023, by the mid-point of
the 2024 CMD production guidance of 46,000 to 48,000 boepd.
The product types comprising the 2P reserves and contingent resources described in this MD&A are contained in the AIF . See also
“Supplemental Information regarding Product Types” below. Light, medium and heavy crude oil and bitumen reserves/resources
disclosed in this MD&A include solution gas and other by-products.
“2P reserves“ means proved plus probable reserves. “Proved reserves“ are those reserves that can be estimated with a high
degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved
reserves. “Probable reserves“ are those additional reserves that are less certain to be recovered than proved reserves. It is equally
likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable
reserves.
Each of the reserves categories reported (proved and probable) may be divided into developed and undeveloped categories.
“Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well)
to put the reserves on production. The developed category may be subdivided into producing and non-producing. “Developed
producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the
estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date
of resumption of production must be known with reasonable certainty. “Developed non-producing reserves” are those reserves
that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption
of production is unknown. “Undeveloped reserves” are those reserves expected to be recovered from known accumulations
where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of
production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known
accumulations using established technology or technology under development, but which are not currently considered to be
commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion
of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be
resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political,
and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered
recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in
accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or
characterized by their economic status.
There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a
classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity
that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best
estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered
will equal or exceed the best estimate.
Contingent resources are further classified based on project maturity. The project maturity subclasses include development
pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources
are classified as either development on hold or development unclarified. Development on hold is defined as a contingent
resource where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved
26
===== SIDA 48 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
that are usually beyond the control of the operator. Development unclarified is defined as a contingent resource that requires
further appraisal to clarify the potential for development and has been assigned a lower chance of development until commercial
contingencies can be clearly defined. Chance of development is the probability of a project being commercially viable. Where
risked resources are presented, they have been adjusted based on the chance of development by multiplying the unrisked values
by the chance of development.
References to “unrisked“ contingent resources volumes means that the reported volumes of contingent resources have not
been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook for
contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies
required for the re-classification of the contingent resources as reserves being resolved. Therefore, unrisked reported volumes
of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such
resources.
The contingent resources reported in this MD&A are estimates only. The estimates are based upon a number of factors and
assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and
commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil
and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks
and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is
uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this MD&A.
2P reserves and contingent resources included in the reports prepared by Sproule and ERCE have been aggregated by IPC.
Estimates of reserves, resources and future net revenue for individual properties may not reflect the same level of confidence
as estimates of reserves, resources and future net revenue for all properties, due to aggregation. This MD&A contains estimates
of the net present value of the future net revenue from IPC’s reserves and contingent resources. The estimated values of future
net revenue disclosed in this MD&A do not represent fair market value. There is no assurance that the forecast prices and cost
assumptions used in the reserve and resources evaluations will be attained and variances could be material.
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel
(bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and
crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an
indication of value.
Supplemental Information regarding Product Types
The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily
production figures provided in this document:
Heavy Crude Oil
(Mbopd)
Light and Medium
Crude Oil (Mbopd)
Conventional Natural Gas
(per day)
Total
(Mboepd)
Three months ended
June 30, 2024 24.3 8.0 96.5 MMcf
(16.1 Mboe) 48.4
June 30, 2023 25.3 9.2 104.0 MMcf
(17.3 Mboe) 51.8
Six months ended
June 30, 2024 24.6 8.0 96.2 MMcf 48.6
(16.0 Mboe)
June 30, 2023 26.0 9.4 102.0 MMcf 52.3
(17.0 Mboe)
Year ended December 31, 2023
December 31, 2023 25.8 8.1 102.8MMcf
(17.1 Mboe) 51.1
This MD&A also makes reference to IPC’s forecast total average daily production of 46,000 to 48,000 boepd for 2024. IPC
estimates that approximately 50% of that production will be comprised of heavy oil, approximately 16% will be comprised of light
and medium crude oil and approximately 34% will be comprised of conventional natural gas.
27
===== SIDA 49 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
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)
OECD Organisation for Economic Co-operation and Development
Oil related terms and measurements
AECO The daily average benchmark price for natural gas at the AECO hub in southeast Alberta
AESO Alberta Electric System Operator
API An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale
ASP Alkaline surfactant polymer (an EOR process)
bbl Barrel (1 barrel = 159 litres)
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.
28
===== SIDA 50 =====
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024
DIRECTORS
C. Ashley Heppenstall
Director, Chair
London, England
William Lundin
Director, President and Chief Executive Officer
Coppet, Switzerland
Chris Bruijnzeels
Director
Abcoude, The Netherlands
Donald K. Charter
Director
Toronto, Ontario, Canada
Lukas (Harry) H. Lundin
Director
Toronto, Ontario, Canada
Emily Moore
Director
Toronto, Ontario, Canada
Mike Nicholson
Director
Monaco
Deborah Starkman
Director
Toronto, Ontario, Canada
OFFICERS
Christophe Nerguararian
Chief Financial Officer
Geneva, Switzerland
Nicki Duncan
Chief Operating Officer
Geneva, Switzerland
Jeffrey Fountain
General Counsel and Corporate Secretary
Geneva, Switzerland
Rebecca Gordon
Senior Vice President Corporate Planning and
Investor Relations
Geneva, Switzerland
Chris Hogue
Senior Vice President, Canada
Calgary, Alberta, Canada
Ryan Adair
Vice President Asset Management and
Corporate Planning, Canada
Calgary, Alberta, Canada
Curtis White
Vice President Commercial, Canada
Calgary, Alberta, Canada
MEDIA AND INVESTOR RELATIONS
Robert Eriksson
Stockholm, Sweden
CORPORATE OFFICE
Suite 2800, 1055 Dunsmuir Street Vancouver,
British Columbia
V7X 1L2 Canada
Telephone: +1 604 689 7842
Website: www.international-petroleum.com
OPERATIONS OFFICE
5 Chemin de la Pallanterie
1222 Vésenaz
Switzerland
Telephone: +41 22 595 10 50
E-mail: info@international-petroleum.com
REGISTERED AND RECORDS OFFICE
Suite 3500 - 1133 Melville Street
Vancouver, British Columbia
V6E 4E5 Canada
INDEPENDENT AUDITORS
PricewaterhouseCoopers LLP , Canada
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta, and Toronto, Ontario
STOCK EXCHANGE LISTINGS
Toronto Stock Exchange and NASDAQ Stockholm
Trading Symbol: IPCO
29
===== SIDA 51 =====
Corporate Office
International Petroleum Corp
Suite 2800
1055 Dunsmuir Street
Vancouver, British Columbia
V7X 1L2, Canada
Tel: +1 604 689 7842
E-mail: info@international-petroleum.com
Web: international-petroleum.com□