FULLTEXT DEL 1 AV 1
Kvartalsrapport Q1 2024
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Q1
International Petroleum Corporation
Interim Condensed Consolidated
Financial Statements
For the three months ended March 31, 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 months ended March 31, 2024 and 2023, UNAUDITED
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3
Interim Condensed Consolidated Statement of Operations
For the three months ended March 31, 2024 and 2023, UNAUDITED
Three months ended March 31
USD Thousands Note 2024 2023
Revenue 2 206,419 192,516
Cost of sales
Production costs 3 (115,745) (117,527)
Depletion and decommissioning costs 8 (33,153) (6,439)
Depreciation of other tangible fixed assets 8 (2,262) (2,558)
Exploration and business development costs (75) (1,609)
Gross profit 2 55,184 64,383
General, administration and depreciation expenses (3,949) (4,194)
Profit before financial items 51,235 60,189
Finance income 4 5,617 4,924
Finance costs 5 (15,387) (9,939)
Net financial items (9,770) (5,015)
Profit before tax 41,465 55,174
Income tax expense 6 (7,746) (15,611)
Net result 33,719 39,563
Net result attributable to:
Shareholders of the Parent Company 33,712 39,557
Non-controlling interest 7 6
33,719 39,563
Earnings per share – USD1 14 0.27 0.29
Earnings per share fully diluted – USD1 14 0.26 0.28
1 Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the interim condensed consolidated financial statements
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Interim Condensed Consolidated Statement of Comprehensive Income
For the three months ended March 31, 2024 and 2023, UNAUDITED
Three months ended March 31
USD Thousands Note 2024 2023
Net result 33,719 39,563
Other comprehensive income
Items that may be reclassified to profit or loss:
Reclassification of hedging (gains)/losses to profit or
loss 2 (9,206) (8,584)
(Loss)/Gain on cash flow hedges (45,419) 4,659
Income tax relating to these items 13,003 986
Currency translation adjustments (22,372) 1,177
Total comprehensive income/(loss) (30,275) 37,801
Total comprehensive income attributable to:
Shareholders of the Parent Company (30,277) 37,792
Non-controlling interest 2 9
(30,275) 37,801
See accompanying notes to the interim condensed consolidated financial statements
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5
Interim Condensed Consolidated Balance Sheet
As at March 31, 2024 and December 31, 2023, UNAUDITED
USD Thousands Note March 31, 2024 December 31, 2023
ASSETS
Non-current assets
Exploration and evaluation assets 7 162 –
Property, Plant and Equipment 8 1,365,777 1,303,860
Right-of-use assets 2,664 2,814
Deferred tax assets 6 834 1,827
Derivative instruments 18 1,840 7,049
Other assets 9 55,212 56,838
Total non-current assets 1,426,489 1,372,388
Current assets
Inventories 10 25,424 21,808
Trade and other receivables 11 104,309 113,497
Derivative instruments 18 1,719 35,504
Current tax receivables 5,162 2,714
Cash and cash equivalents 12 397,390 517,074
Total current assets 534,004 690,597
TOTAL ASSETS 1,960,493 2,062,985
LIABILITIES
Non-current liabilities
Financial liabilities 15 4,444 5,442
Bonds 15 436,242 435,041
Lease liabilities 2,291 2,087
Provisions 16 250,095 250,657
Deferred tax liabilities 6 78,258 86,348
Derivative instruments 18 1,072 263
Total non-current liabilities 772,402 779,838
Current liabilities
Trade and other payables 17 152,200 188,871
Financial liabilities 18 3,518 3,589
Derivative instruments 18 16,557 1,267
Current tax liabilities 680 255
Lease liabilities 464 809
Provisions 16 8,279 8,097
Total current liabilities 181,698 202,888
EQUITY
Shareholders’ equity 1,006,206 1,080,074
Non-controlling interest 187 185
Net shareholders’ equity 1,006,393 1,080,259
TOTAL EQUITY AND LIABILITIES 1,960,493 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 months ended March 31, 2024 and 2023, UNAUDITED
Three months ended March 31
USD Thousands Note 2024 2023
Cash flow from operating activities
Net result 33,719 39,563
Adjustments for non-cash related items:
Depletion, depreciation and amortization 7,8 35,710 9,380
Income tax 6 7,746 15,611
Amortization of capitalized financing fees 5 425 279
Foreign currency exchange loss/(gain) 5 2,061 856
Interest expense 5 8,818 5,349
Interest income 4 (5,617) (4,924)
Unwinding of asset retirement obligation discount 5 3,618 3,068
Share-based costs 1,934 2,587
Other 271 342
Cash flow generated from operations (before
working capital adjustments and income taxes) 88,685 72,111
Changes in working capital (48,960) (14,593)
Decommissioning costs paid 16 (122) (1,211)
Other payments 16 (504) (290)
Income taxes paid (3,465) (3,584)
Interest received 5,011 4,965
Interest paid (16,366) (10,947)
Net cash flow from operating activities 24,279 46,451
Cash flow used in investing activities
Investment in oil and gas properties 7 (125,256) (48,238)
Acquisitions net of cash acquired – (59,180)
Investment in other fixed assets 8 (55) (172)
Net cash (outflow) from investing activities (125,311) (107,590)
Cash flow from financing activities
Repayments 15 (1,069) (856)
Paid financing fees – (507)
Repurchase of own shares (“NCIB”) 13 (17,308) (45,830)
Other payments (223) (186)
Net cash (outflow) from financing activities (18,600) (47,379)
Change in cash and cash equivalents (119,632) (108,518)
Cash and cash equivalents at the beginning of the
period 517,074 487,240
Currency exchange difference in cash and cash
equivalents (52) (256)
Cash and cash equivalents at the end of the period 397,390 378,466
See accompanying notes to the interim condensed consolidated financial statements
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7
Interim Condensed Consolidated Statement of Changes in Equity
For the three months ended March 31, 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 – 33,712 – – – – 33,712 7 33,719
Cash flow hedge – – – – (41,622) – (41,622) – (41,622)
Currency translation difference – – (19,868) (2,031) (468) – (22,367) (5) (22,372)
Total comprehensive income – 33,712 (19,868) (2,031) (42,090) – (30,277) 2 (30,275)
Repurchase of own shares
(NCIB)1 (17,654) – – – – – (17,654) – (17,654)
Share based costs – – – 1,934 – – 1,934 – 1,934
Share based payments2 (21,740) – – (6,131) – – (27,871) – (27,871)
Balance at March 31, 2024 190,611 842,558 (30,613) 12,610 (10,746) 1,786 1,006,206 187 1,006,393
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 – 39,557 – – – – 39,557 6 39,563
Acquisitions – – – – 881 – 881 – 881
Cash flow hedge – – – – (3,820) – (3,820) – (3,820)
Currency translation difference – – 1,321 (153) 6 – 1,174 3 1,177
Total comprehensive income – 39,557 1,321 (153) (2,933) – 37,792 9 37,801
Repurchase of own shares
(NCIB)1 (45,830) – – – – – (45,830) – (45,830)
Share based costs – – – 2,587 – – 2,587 – 2,587
Share based payments2 (12,931) – – (5,640) – – (18,571) – (18,571)
Balance at March 31, 2023 279,958 675,452 (29,971) 8,143 5,025 2,511 941,118 200 941,318
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 months ended March 31, 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 May 7, 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 three months period ended March 31, 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 three months ended March 31, 2024, the Group applied the amended accounting standards, interpretations and annual
improvement points that are effective as of January 1, 2024.
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Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 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 March 31, 2024
USD Thousands Canada Malaysia France Other Total
Crude oil 169,616 18,553 16,717 – 204,886
NGLs 244 – – – 244
Gas 14,417 – – – 14,417
Net sales of oil and gas 184,277 18,553 16,717 – 219,547
Change in under/over lift position – – 2,916 – 2,916
Royalties (24,483) – (1,139) – (25,622)
Hedging settlement 9,206 – – – 9,206
Other operating revenue – – 217 155 372
Revenue 169,000 18,553 18,711 155 206,419
Operating costs (59,889) (7,016) (8,911) – (75,816)
Cost of blending (45,206) – – – (45,206)
Change in inventory position 139 5,039 99 – 5,277
Depletion and decommissioning costs (22,904) (7,030) (3,219) – (33,153)
Depreciation of other tangible fixed assets – (2,262) – – (2,262)
Exploration and business development costs – – – (75) (75)
Gross profit 41,140 7,284 6,680 80 55,184
Three months ended March 31, 2023
USD Thousands Canada Malaysia France Other Total
Crude oil 147,731 17,671 15,131 – 180,533
NGLs 190 – – – 190
Gas 20,483 – – – 20,483
Net sales of oil and gas 168,404 17,671 15,131 – 201,206
Change in under/over lift position – – 2,670 – 2,670
Royalties (18,665) – (1,474) – (20,139)
Hedging settlement 8,584 – – – 8,584
Other operating revenue 6 – 189 – 195
Revenue 158,329 17,671 16,516 – 192,516
Operating costs (59,531) (8,176) (7,738) – (75,445)
Cost of blending (47,817) – – – (47,817)
Change in inventory position (422) 5,872 285 – 5,735
Depletion and decommissioning costs1 2,523 (5,829) (3,133) – (6,439)
Depreciation of other tangible fixed assets – (2,558) – – (2,558)
Exploration and business development costs (831) – – (778) (1,609)
Gross profit/(loss) 52,251 6,980 5,930 (778) 64,383
1 In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program.
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Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2024 and 2023, UNAUDITED
3. PRODUCTION COSTS
Three months ended March 31
USD Thousands 2024 2023
Cost of operations 65,013 64,774
Tariff and transportation expenses 9,543 9,499
Direct production taxes 1,260 1,172
Operating costs 75,816 75,445
Cost of blending1 45,206 47,817
Change in inventory position (5,277) (5,735)
Total production costs 115,745 117,527
1 In Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications. Cost of blending represents the contracted
purchase of diluent used for blending.
4. FINANCE INCOME
Three months ended March 31
USD Thousands 2024 2023
Interest income 5,617 4,924
Total finance income 5,617 4,924
5. FINANCE COSTS
Three months ended March 31
USD Thousands 2024 2023
Foreign exchange loss, net 2,061 856
Interest expense 8,818 5,349
Unwinding of asset retirement obligation discount 3,618 3,068
Amortization of financing fees 425 279
Amortization of loan fees 85 164
Loan commitment fees 222 88
Other financial costs 158 135
Total finance costs 15,387 9,939
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Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2024 and 2023, UNAUDITED
6. INCOME TAX
Three months ended March 31
USD Thousands 2024 2023
Current tax (1,373) (3,991)
Deferred tax (6,373) (11,620)
Total tax expense (7,746) (15,611)
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.
Specification of deferred tax assets and tax liabilities1
USD Thousands March 31, 2024 December 31, 2023
Unused tax loss carry forward 31,999 34,446
Derivative hedges 3,237 –
Other 4,812 5,959
Deferred tax assets 40,048 40,405
Accelerated allowances 117,472 115,399
Derivative hedges – 9,527
Deferred tax liabilities 117,472 124,926
Deferred taxes, net (77,424) (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.
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7. EXPLORATION AND EVALUATION ASSETS
USD Thousands Canada Malaysia France Total
Cost
January 1, 2024 – – – –
Additions – 162 – 162
Net book value March 31, 2024 – 162 – 162
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 1,342,660 1,278,422
Other tangible fixed assets 23,117 25,438
Property, Plant and Equipment 1,365,777 1,303,860
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 110,104 14,200 790 125,094
Change in estimates 731 – – 731
Currency translation adjustments (35,333) – (9,361) (44,694)
March 31, 2024 1,540,512 605,323 428,122 2,573,957
Accumulated depletion
January 1, 2024 (398,288) (502,834) (313,282) (1,214,404)
Depletion charge for the period (22,904) (7,030) (3,219) (33,153)
Currency translation adjustments 9,559 – 6,701 16,260
March 31, 2024 (411,633) (509,864) (309,800) (1,231,297)
Net book value March 31, 2024 1,128,879 95,459 118,322 1,342,660
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2024 and 2023, UNAUDITED
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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.
Other tangible fixed assets
USD Thousands FPSO Other Total
Cost
January 1, 2024 204,853 10,048 214,901
Additions – 55 55
Currency translation adjustments – (192) (192)
March 31, 2024 204,853 9,911 214,764
Accumulated depreciation
January 1, 2024 (181,123) (8,340) (189,463)
Depreciation charge for the period (2,262) (78) (2,340)
Currency translation adjustments – 156 156
March 31, 2024 (183,385) (8,262) (191,647)
Net book value March 31, 2024 21,468 1,649 23,117
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2024 and 2023, UNAUDITED
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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 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.
9. OTHER NON-CURRENT ASSETS
USD Thousands March 31, 2024 December 31, 2023
Financial assets 40,359 41,486
Intangible assets 14,853 15,352
55,212 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 27.9 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 4.5 million.
Intangible assets mainly represent carbon offsets purchased in Canada.
10. INVENTORIES
USD Thousands March 31, 2024 December 31, 2023
Hydrocarbon stocks 18,318 13,530
Well supplies and operational spares 7,106 8,278
25,424 21,808
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2024 and 2023, UNAUDITED
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11. TRADE AND OTHER RECEIVABLES
USD Thousands March 31, 2024 December 31, 2023
Trade receivables 85,036 97,264
Underlift 3,911 1,029
Joint operations debtors 995 910
Prepaid expenses and accrued income 11,646 10,986
Other 2,721 3,308
104,309 113,497
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) (1,553,906)
Balance at March 31, 2024 125,438,160
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.
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 Q1 2024, IPC purchased and cancelled a total of 1,553,906 common shares under the NCIB. The average price of common
shares purchased during Q1 2024 was SEK 115/ CAD 15 per share.
As at March 31, 2024, IPC had a total of 125,438,160 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.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2024 and 2023, UNAUDITED
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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 March 31
2024 2023
Net result attributable to shareholders of the Parent Company, USD 33,712,061 39,556,554
Weighted average number of shares for the period 126,974,800 136,774,538
Earnings per share, USD 0.27 0.29
Weighted average diluted number of shares for the period 128,276,966 138,932,433
Earnings per share fully diluted, USD 0.26 0.28
15. FINANCIAL LIABILITIES
USD Thousands March 31, 2024 December 31, 2023
Bank loans 7,962 9,031
Bonds 441,063 440,288
Capitalized financing fees (4,821) (5,247)
444,204 444,072
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
March 31, 2024, IPC had a nominal USD 450 million of bonds outstanding with maturity in February 2027. The bond repayment
obligations as at March 31, 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 CAD 75 to CAD 180 million and extended the maturity to May 2025. No
cash amounts were drawn under the Canadian RCF as at March 31, 2024.
As at March 31, 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
March 31, 2024 was USD 8 million (EUR 7 million). An amount of USD 3.5 million (EUR 3.2 million) drawn under the France Facility
as at March 31, 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 March 31, 2024.
Total net debt as at March 31, 2024 amounted to USD 61 million. Cash and cash equivalents held amounted to USD 397 million as
at March 31, 2024.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 2024 and 2023, UNAUDITED
===== SIDA 17 =====
17
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 – – – 114 114
Unwinding of asset retirement obligation discount 3,618 – – – 3,618
Payments (122) – – (504) (626)
Change in estimates 731 – – – 731
Currency translation adjustments (4,137) (63) – (17) (4,217)
March 31, 2024 254,039 2,113 551 1,671 258,374
Non-current 246,817 1,056 551 1,671 250,095
Current 7,222 1,057 – – 8,279
Total 254,039 2,113 551 1,671 258,374
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 months ended March 31, 2024 and 2023, UNAUDITED
===== SIDA 18 =====
18
17. TRADE AND OTHER PAYABLES
USD Thousands March 31, 2024 December 31, 2023
Trade payables 20,194 42,761
Joint operations creditors 11,738 22,257
Accrued expenses 117,222 118,912
Other 3,046 4,941
152,200 188,871
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:
March 31, 2024
USD Thousands
Total
Financial assets
at amortized
cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Other assets1 55,212 55,212 – –
Derivative instruments 3,559 – – 3,559
Joint operation debtors 995 995 – –
Other current receivables2 96,830 92,919 3,911 –
Cash and cash equivalents 397,390 397,390 – –
Financial assets 553,986 546,516 3,911 3,559
1 See Note 9
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
March 31, 2024
USD Thousands
Total
Financial
liabilities at
amortized cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Non-current financial liabilities 440,686 440,686 – –
Current financial liabilities 3,518 3,518 – –
Derivative instruments 17,629 – – 17,629
Joint operation creditors 11,738 11,738 – –
Other current liabilities 141,142 141,142 – –
Financial liabilities 614,713 597,084 – 17,629
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 41,486 41,486 – –
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 706,338 662,756 1,029 42,553
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 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
The carrying amount of the Group’s financial assets and liabilities approximate their fair values at the balance sheet dates.
For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
– Level 1: based on quoted prices in active markets;
– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
– Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
March 31, 2024
USD Thousands Level 1 Level 2 Level 3
Other current receivables 3,911 – –
Derivative instruments – current – 1,719 –
Derivative instruments – non-current – 1,840 –
Financial assets 3,911 3,559 –
Derivative instruments – current – 16,557 –
Derivative instruments – non-current – – 1,072
Financial liabilities – 16,557 1,072
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 months ended March 31, 2024 and 2023, UNAUDITED
===== SIDA 20 =====
20
The Group had oil price sale financial hedges outstanding as at March 31, 2024 which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
April 1, 2024 - December 31, 2024 17,700 WTI/WCS Differential USD -15.03/bbl
April 1, 2024 - December 31, 2024 8,250 WTI Sale Swap USD 80.01/bbl
The Group had electricity financial hedges outstanding as at March 31, 2024 which are summarized as follows:
Period Volume (MW) Type Average Pricing
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
The Group had no gas price sale financial hedges outstanding as at March 31, 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 respect of the forecast
Blackrod development capital expenditure in Canada, IPC entered into further currency hedges to purchase a total CAD 556 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 March 31, 2024:
CAD Millions 2024 2025 2026 2027 2028 Thereafter
Transportation service 1 21.0 29.2 38.4 43.4 46.4 555.6
Power2 8.7 12.4 12.4 12.4 9.8 –
Total commitments 29.7 41.6 50.8 55.8 56.2 555.6
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 15MW at a weighted average price of CAD 74.92/MWh from April 1, 2024 to December 31,
2028 and an additional 5MW at a weighted average price of CAD 58.31/MWh from July 1, 2024 to December 31, 2027.
20. RELATED PARTIES
During the three months ended March 31, 2024, the Group paid USD 111 thousand to the Lundin Foundation in respect of
sustainability advisory services provided to the Group and USD 193 thousand to Orrön Energy in respect of office space rental for
the first quarter 2024.
During the three months ended March 31, 2024, Orrön Energy paid USD 168 thousand to the Group in respect of support services
provided to Orrön Energy during the first quarter 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 April 2024, the Group also entered into the following oil price sale financial hedges in Canada:
Period Volume (barrels per day) Type Average Pricing
April 1, 2024 - December 31, 2024 4,000 WTI Sale Swap USD - 80.76/bbl
April 1, 2024 - December 31, 2024 3,000 Brent Sale Swap USD - 85.50/bbl
In April 2024, IPC entered into currency hedge swaps from May 2024 to December 20024 to buy EUR 2.5 million per month, sell
USD at an average exchange rate of 1.0705.
No other events have occurred since March 31, 2024, that are expected to have a substantial effect on this report.
Notes to the Interim Condensed Consolidated Financial Statements
For the three months ended March 31, 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 =====
Q1
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three months ended March 31, 2024
===== SIDA 23 =====
Management’s Discussion and Analysis
For the three months ended March 31, 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 16.
Forward-Looking Statements
Certain statements contained in this MD&A constitute “forward-looking statements” or “forward-looking information” (within the meaning of applicable securities
legislation). Such statements and information (together, “forward-looking statements”) relate to future events, including the Corporation’s future performance, business
prospects or opportunities. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts,
guidance, budgets, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“,
“continue“, “estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, “might“, “should“, “believe“, “budget“
and similar expressions) are not statements of historical fact and may be “forward-looking statements“. Although IPC believes that the expectations and assumptions
on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no
assurances that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks
and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. For additional information underlying
forward-looking statements, refer to the “Cautionary Statement Regarding Forward-Looking Information” on page 22.
Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada are effective as of December
31, 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 15
• Financial Position and Liquidity 16
• Non-IFRS Measures 16
• Off-Balance Sheet Arrangements 19
• Outstanding Share Data 19
• Contractual Obligations and Commitments 19
• Critical Accounting Policies and Estimates 19
• Transactions with Related Parties 19
• Financial Risk Management 20
RISK FACTORS 21
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING 21
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 22
RESERVES AND RESOURCES ADVISORY 24
OTHER SUPPLEMENTARY INFORMATION 26
2
===== SIDA 24 =====
Management’s Discussion and Analysis
For the three months ended March 31, 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 May 7, 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 interim
condensed consolidated financial statement for the period ended March 31, 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 IFRS Accounting Standards (“IFRS”) as issued by
the International Accounting Standards Board (“IASB”).
Financial information is presented in United States Dollars (“USD”). However, as the Group operates in Europe and in Canada,
certain financial information prepared by subsidiaries has been reported in Euros (“EUR”) and in Canadian Dollars (“CAD”). In
addition, certain costs relating to the operations in Malaysia, which are reported in USD, are incurred in Malaysian Ringgit (“MYR”).
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
March 31, 2024 March 31, 2023 December 31, 2023
Average Period end Average Period end Average Period end
1 EUR equals USD 1.0857 1.0811 1.0730 1.0875 1.0816 1.1050
1 USD equals CAD 1.3484 1.3571 1.3521 1.3551 1.3496 1.3251
1 USD equals MYR 4.7234 4.7330 4.3865 4.4125 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 months ended March 31, 2024
HIGHLIGHTS
Q1 2024 Business Highlights
• Average net production of approximately 48,800 boepd for the first quarter of 2024 was above the high end of the guidance
range for the period (51% heavy crude oil, 16% 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.
• Successfully drilled, completed and tied-in three out of five 2024 budgeted Ellerslie wells within the Suffield area.
• 1.6 million IPC common shares purchased and cancelled during Q1 2024 under IPC’s normal course issuer bid (NCIB) and
continuing with target to complete the full 2023/2024 NCIB this year.
Q1 2024 Financial Highlights
• Operating costs per boe of USD 17.1 for Q1 2024, below guidance.(3)
• Operating cash flow (OCF) generation of MUSD 89 for Q1 2024, ahead of the guidance range .(3)
• Capital and decommissioning expenditures of MUSD 125 for Q1 2024, in line with guidance.
• Free cash flow (FCF) generation for Q1 2024 amounted to MUSD -43 (MUSD 53 pre-Blackrod Phase 1 project funding) .(3)
• Gross cash of MUSD 397 and net debt of MUSD 61 as at March 31, 2024. (3)
• Net result of MUSD 34 for Q1 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 guidance range maintained at USD 18 to 19 per boe. (3)
• Full year 2024 OCF guidance estimated at between MUSD 323 and 363 (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 -154 and -114 (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 and the additional oil hedges executed in March and April 2024 .(3)
Three months ended March 31
USD Thousands 2024 2023
Revenue 206,419 192,516
Gross profit 55,184 64,383
Net result 33,719 39,563
Operating cash flow(3) 89,301 75,900
Free cash flow(3) (43,311) 16,259
EBITDA(3) 87,020 76,079
Net cash/(debt)(3) (60,572) 66,956
4
===== SIDA 26 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
OPERATIONS REVIEW
Business Overview
During the first quarter of 2024, oil prices remained strong, with Brent prices averaging USD 83 per barrel. Following the quarter,
Brent prices increased to spot rates over USD 91 per barrel in April 2024. Increased global crude demand revisions in combination
with downward supply adjustments largely influenced by extended OPEC+ curtailments and rising geopolitical tension in the
Middle East are some of the key factors that have lead to higher oil prices. Global crude inventories were largely unchanged in
the first quarter and are below the 5 year average. Current consensus is that the oil market will be in a deficit for the remainder of
2024.
IPC has taken advantage of the favourable pricing outlook by increasing our benchmark hedged volumes to around 50% of our oil
production at approximately USD 80.3 and USD 85.5 per barrel for West Texas Intermediate (WTI) and Dated Brent, respectively,
for the remainder of 2024. Despite a favourable outlook for crude prices, 2024 is an election year in the United States and with
recent inflation data impacting rate cut decisions, IPC took prudent action to protect the business in a downside pricing scenario
given the record investment year for the Corporation.
In Canada, first quarter 2024 WTI to Western Canadian Select (WCS) crude price differentials averaged around USD 19 per barrel,
with differentials decreasing to around USD 12 per barrel in April 2024. The Trans-Mountain (TMX) pipeline began commercial
operations in May 2024 which should benefit future WTI/WCS differentials. Another positive catalyst for WCS is the reduced
Mexican heavy oil exports to the US. IPC has hedged the WTI/WCS differential for approximately 70% of our Canadian crude
production at USD 15 per barrel for 2024.
Gas markets in the first quarter of 2024 were relatively weak, given the warmer than average weather conditions and high gas
storage levels in North America. The average AECO gas price was CAD 2.50 per Mcf for the first quarter of 2024.
First Quarter 2024 Highlights and Full Year 2024 Guidance
During the first quarter of 2024, our assets delivered average net production of 48,800 boepd, ahead of guidance for the quarter.
High uptime performance was achieved across all our assets, including resumed production in Malaysia following the completion
of the previously announced well maintenance work. IPC also benefited from short cycle investment activities, mainly within
Southern Alberta assets in Canada where three out of five 2024 budgeted Ellerslie wells have been successfully drilled. We
maintain the full year 2024 average net production guidance range of 46,000 to 48,000 boepd.(1)
Our operating costs per boe for the first quarter of 2024 was USD 17.1, below guidance. Full year 2024 operating costs per boe
guidance of USD 18.0 to 19.0 per boe remains unchanged.(3)
Operating cash flow (OCF) generation for the first quarter of 2024 was MUSD 89. Full year 2024 OCF guidance is tightened to
MUSD 323 to 363 (assuming Brent USD 70 to 90 per boe for the remainder of 2024).(3)
Capital and decommissioning expenditure for the first quarter of 2024 was MUSD 125 in line with guidance. Full year 2024 capital
and decommissioning expenditure of MUSD 437 is unchanged.
Free cash flow (FCF) generation was MUSD -43 (MUSD 53 pre-Blackrod Phase 1 project funding) during the first quarter of 2024.
Full year 2024 FCF guidance is tightened to MUSD -154 to -114(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 and the additional oil hedges executed in March and April 2024 .(3)
As at March 31, 2024, IPC’s net debt position was MUSD 61, from a net cash position of MUSD 58 as at December 31, 2023,
largely driven by the funding of forecast capital expenditures and the continuing share repurchase program (NCIB).(3) Gross cash
on the balance sheet as at March 31, 2024 amounts to MUSD 397 providing a significant war chest to pursue our three strategic
pillars of organic growth, returning value to stakeholders, and pursuing value adding M&A.
Blackrod Project
In Q1 2024, IPC continued to advance the development of Phase 1 of the Blackrod project. Development capital expenditure
to first oil is estimated at MUSD 850. First oil of the Phase 1 development is estimated to be in late 2026, with forecast net
production of 30,000 bopd by 2028. IPC forecasts development capital expenditure in 2024 for the Blackrod Phase 1 project of
MUSD 362, of which MUSD 96 was invested in Q1 2024.(1)
Project activities for the multi-year Blackrod Phase 1 development have progressed in line with expectations. As at the end of Q1
2024, fabrication and installation have commenced, site civil and commercial road expansion works continue to advance, drilling
is progressing, and third-party pipeline commercial agreements are moving forward according to plan. IPC intends to fund the
remaining Blackrod Phase 1 development costs with forecast cash flow generated by its operations and cash on hand.(3)
5
===== SIDA 27 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
Stakeholder Returns: Normal Course Issuer Bid
In Q4 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 1.6 million common shares during Q1 2024. The
average price of common shares purchased under the 2023/2024 NCIB during Q1 2024 was SEK 115 / CAD 15 per share.
As at March 31, 2024, IPC had a total of 125,438,160 common shares issued and outstanding and IPC held no common shares in
treasury. As at April 30, 2024, IPC had a total of 125,151,742 common shares issued and outstanding and IPC held no 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 April 1, 2024 of 5.5 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
During the first 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.
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.
6
===== SIDA 28 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
Operations Overview
Q1 2024 Overview
In Q1 2024, IPC continued to successfully demonstrate its commitment to operational excellence, with higher than forecasted net
average daily production and no material safety incidents or harm to the environment.
In Canada, the Blackrod Phase 1 project development continues to progress in line with expectations. As at the end of Q1 2024,
process facility fabrication and critical equipment site installation has commenced, site civil and commercial road expansion works
continue to advance, utility well and well Pad drilling is progressing ahead of plan, and third-party pipeline commercial agreements
are moving forward. At Onion Lake Thermal, daily production remained strong through the quarter as we gradually phase in the
new wells from the latest production sustaining Pad L. At Suffield, three new production wells in the exciting Ellerslie play have
been brought online in the quarter and are producing in line with expectations. At Bertam in Malaysia, the previously announced
well maintenance workovers have been completed with both wells returning to production in Q1 2024. In France, the focus
remains on maturing the next round of development targets with field development studies progressing in line with expectations.
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 optimisation opportunities ready
for sanction at the discretion of the Group.
Production
Average daily net production for the first quarter 2024 was ahead of IPC’s high end guidance at 48,800 boepd with continued
strong performance at our major producing assets. In Canada, exceptional operational performance has been supplemented by
recent Suffield area Ellerslie production well drilling and continued ahead of expectations results from production sustaining Pad L
at Onion Lake Thermal. In addition, IPC continues to benefit from high facility uptime and strong production well performance post
the planned maintenance workovers at Bertam in Malaysia.
With exceptional operational delivery through the first quarter of 2024, and a strong production outlook for the remainder of the
year, IPC is well positioned to deliver an annual net average daily production within the guidance range of 46,000 to 48,000 boepd.
The production during Q1 2024 with comparatives is summarized below:
Production
in Mboepd
Three months ended
March 31
Year ended
December 31
2024 2023 2023
Crude oil
Canada – Northern Assets 15.0 15.8 15.5
Canada – Southern Assets1 11.2 12.7 11.8
Malaysia 4.1 5.1 3.8
France 2.5 2.5 2.8
Total crude oil production 32.8 36.1 33.9
Gas
Canada – Northern Assets 0.3 0.4 0.4
Canada – Southern Assets 15.7 16.3 16.8
Total gas production 16.0 16.7 17.2
Total production 48.8 52.8 51.1
Quantity in MMboe 4.44 4.75 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 months ended March 31, 2024
CANADA
Production
in Mboepd
Working
Interest
(WI)
Three months ended
March 31
Year ended
December 31
2024 2023 2023
- Oil Onion Lake Thermal 100% 13.3 13.3 13.3
- Oil Suffield Area1 100% 10.0 10.7 10.2
- Oil Other 50-100% 2.9 4.5 3.8
- Gas1 ~100% 16.0 16.7 17.2
Canada 42.2 45.2 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 Canadian assets during Q1 2024 was in line with guidance at 42,200 boepd with continued strong
operational performance at all the major producing assets. At Onion Lake Thermal, daily production remained high through the
quarter as we continue to phase in new wells from the latest production sustaining Pad L. The Suffield area oil and gas producing
assets continue to deliver above forecast, where base well rate optimization has been supplemented with three newly drilled
Ellerslie play oil wells.
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
optimisation is the priority with a continued phased ramp up of the latest production sustaining Pad L planned.
During the first quarter of 2024, the Blackrod Phase 1 project development continues to progress in line with expectations. As at
the end of Q1 2024, process facility fabrication and critical equipment site installation has commenced, site civil and commercial
road expansion works continue to advance, utility well and well Pad drilling is progressing ahead of plan, and third-party pipeline
commercial agreements are moving forward.
As of the end of Q1 2024 in the Suffield area, three out of five budgeted Ellerslie play wells have been drilled and brought online
with performance in line with expectations. The drilling rig has relocated to the Ferguson asset to undertake a planned three well
program prior to returning to Suffield to drill the final two budgeted Ellerslie play wells in 2024.
At Onion Lake Thermal, daily production is close to the facility nameplate capacity of 14,000 boepd with the fifth well pair from
production sustaining Pad L brought online in the quarter. The sixth and seventh Pad L wells are planned to be brought online in
Q2 and Q3 2024 respectively.
MALAYSIA
Production
in Mboepd WI
Three months ended
March 31
Year ended
December 31
2024 2023 2023
Bertam 100% 4.1 5.1 3.8
Production
Net production at Bertam in Malaysia in Q1 2024 was above guidance at 4.1 boepd, with IPC benefiting from high facility uptime
and strong production performance post completion of the two planned well workovers earlier in the quarter.
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 months ended March 31, 2024
FRANCE
Production
in Mboepd WI
Three months ended
March 31
Year ended
December 31
2024 2023 2023
France
- Paris Basin 100%1 2.1 2.1 2.4
- Aquitaine 50% 0.4 0.4 0.4
2.5 2.5 2.8
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q1 2024 was slightly below guidance at 2,500 boepd due to well maintenance activity. Well
maintenance has been completed and production is now in line with forecast.
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 months ended March 31, 2024
FINANCIAL REVIEW
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands Q1-24 Q4-23 Q3-23 Q2-23 Q1-23 Q4-22 Q3-22 Q2-22
Revenue 206,419 198,460 257,366 205,564 192,516 254,615 299,361 315,540
Gross profit 55,184 39,955 93,429 52,747 64,383 95,411 140,489 161,709
Net result 33,719 29,710 71,681 32,025 39,563 61,183 90,503 105,217
Earnings per share – USD 0.27 0.23 0.56 0.24 0.29 0.45 0.63 0.70
Earnings per share fully
diluted – USD 0.26 0.22 0.54 0.24 0.28 0.44 0.62 0.68
Operating cash flow1 89,301 73,634 119,142 84,372 75,900 113,668 171,654 192,515
Free cash flow1 (43,311) (64,688) 34,703 16,415 16,259 65,288 116,681 151,792
EBITDA1 87,020 66,284 123,054 85,201 76,079 125,651 174,328 194,038
Net cash/(debt) at period end1 (60,572) 58,043 83,097 63,548 66,956 175,098 88,615 14,382
1 See definition on page 16 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands March 31, 2024 December 31, 2023
Non-current assets 1,426,489 1,372,388
Current assets 534,004 690,597
Total assets 1,960,493 2,062,985
Total non-current liabilities 772,402 779,838
Current liabilities 181,698 202,888
Total liabilities 954,100 982,726
Net assets 1,006,393 1,080,259
Working capital (including cash) 352,306 487,709
10
===== SIDA 32 =====
Management’s Discussion and Analysis
For the three months ended March 31, 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 – March 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 104,145 65,471 18,553 16,717 – 204,886
NGLs – 244 – – – 244
Gas 125 14,292 – – – 14,417
Net sales of oil and gas 104,270 80,007 18,553 16,717 – 219,547
Change in under/over lift position – – – 2,916 – 2,916
Royalties (15,495) (8,988) – (1,139) – (25,622)
Hedging settlement 5,255 3,951 – – – 9,206
Other operating revenue – – – 217 155 372
Revenue 94,030 74,970 18,553 18,711 155 206,419
Operating costs (20,658) (39,231) (7,016) (8,911) – (75,816)
Cost of blending (38,294) (6,912) – – – (45,206)
Change in inventory position 368 (229) 5,039 99 – 5,277
Depletion (9,744) (13,160) (7,030) (3,219) – (33,153)
Depreciation of other assets – – (2,262) – – (2,262)
Exploration and business
development costs – – – – (75) (75)
Gross profit 25,702 15,438 7,284 6,680 80 55,184
Three months ended – March 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia1 France Other Total
Crude oil 95,829 51,902 17,671 15,131 – 180,533
NGLs – 190 – – – 190
Gas 94 20,389 – – – 20,483
Net sales of oil and gas 95,923 72,481 17,671 15,131 – 201,206
Change in under/over lift position – – – 2,670 – 2,670
Royalties (10,819) (7,846) – (1,474) – (20,139)
Hedging settlement 636 7,948 – – – 8,584
Other operating revenue – 6 – 189 – 195
Revenue 85,740 72,589 17,671 16,516 – 192,516
Operating costs (25,033) (34,498) (8,176) (7,738) – (75,445)
Cost of blending (40,740) (7,077) – – – (47,817)
Change in inventory position (461) 39 5,872 285 – 5,735
Depletion1 3,105 (582) (5,829) (3,133) – (6,439)
Depreciation of other assets – – (2,558) – – (2,558)
Exploration and business
development costs – (831) – – (778) (1,609)
Gross profit/(loss) 22,611 29,640 6,980 5,930 (778) 64,383
1 In Canada, includes an adjustment for accelerated decommissioning activities funded by a non cash site rehabilitation program.
11
===== SIDA 33 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
Three months March 31, 2024, Review
Revenue
Total revenue amounted to USD 206,419 thousand for Q1 2024, compared to USD 192,516 thousand for Q1 2023 and is analyzed
as follows:
USD Thousands
Three months ended March 31
2024 2023
Crude oil sales 204,886 180,533
Gas and NGL sales 14,661 20,673
Change in under/overlift position 2,916 2,670
Royalties (25,622) (20,139)
Hedging settlement 9,206 8,584
Other operating revenue 372 195
Total revenue 206,419 192,516
The main components of total revenue for Q1 2024 and Q1 2023 respectively, are detailed below.
Crude oil sales
Three months ended – March 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 104,145 65,471 18,553 16,717 204,886
- Quantity sold in bbls 1,826,774 1,127,014 202,519 201,604 3,357,911
- Average price realized USD per bbl 57.01 58.09 91.61 82.92 61.02
Three months ended – March 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 95,829 51,902 17,671 15,131 180,533
- Quantity sold in bbls 1,914,797 976,258 205,338 185,934 3,282,327
- Average price realized USD per bbl 50.05 53.16 86.06 81.38 55.00
Crude oil revenue was 13% higher in Q1 2024 compared to Q1 2023 mainly due to higher oil prices. Canadian - Southern Assets
sales volumes are 15% higher in Q1 2024 compared to Q1 2023 as a result of the Brooks assets acquired in March 2023.
The Suffield area assets and Onion Lake Thermal crude oil in Canada is blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada. The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q1 2024, WTI averaged USD 77 per bbl compared to USD 76 per bbl for Q1 2023 and the
average discount to WCS used in IPC’s pricing formula was USD 19 per bbl compared to USD 25 per bbl for Q1 2023.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia
during Q1 2024 and one cargo lifting in Q1 2023. Produced unsold oil barrels from Bertam at the end of Q1 2024 amounted to
279,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 83 per bbl for
Q1 2024 compared to USD 81 per bbl for the comparative period.
12
===== SIDA 34 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
Gas and NGL sales
Three months ended – March 31, 2024
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 125 14,536 14,661
- Quantity sold in Mcf 70,491 7,668,608 7,739,099
- Average price realized USD per Mcf 1.77 1.90 1.89
Three months ended – March 31, 2023
Canada –
Northern Assets
Canada –
Southern Assets Total
Gas and NGL sales
- Revenue in USD thousands 94 20,579 20,673
- Quantity sold in Mcf 53,049 7,645,299 7,698,348
- Average price realized USD per Mcf 1.76 2.69 2.69
Gas and NGL sales revenue was 29% lower for Q1 2024 compared to Q1 2023 mainly due to the lower achieved gas price. IPC’s
achieved gas price is based on AECO pricing plus a premium. For Q1 2024, IPC realized an average price of CAD 2.52 per Mcf
compared to AECO average pricing of CAD 2.49 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 Q1 2024 amounted to a gain of USD 9,206 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 115,745 thousand for Q1 2024 compared to USD 117,527
thousand for Q1 2023 and is analyzed as follows:
Three months ended – March 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 20,658 39,231 11,066 8,911 (4,050) 75,816
USD/boe2 14.89 16.05 29.36 38.89 n/a 17.09
Cost of blending 38,294 6,912 – – – 45,206
Change in inventory position (368) 229 (5,039) (99) – (5,277)
Production costs 58,584 46,372 6,027 8,812 (4,050) 115,745
13
===== SIDA 35 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
Three months ended – March 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other3 Total
Operating costs1 25,033 34,498 12,226 7,738 (4,050) 75,445
USD/boe2 17.16 15.80 26.76 34.52 n/a 17.31
Cost of blending 40,740 7,077 – – – 47,817
Change in inventory position 461 (39) (5,872) (285) – (5,735)
Production costs 66,234 41,536 6,354 7,453 (4,050) 117,527
1 See definition on page 16 under “Non-IFRS measures”.
2 USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and for 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 18.61 for Q1 2024 and USD 17.90 for the comparative period.
Operating costs
Operating costs amounted to USD 75,816 thousand for Q1 2024 compared to USD 75,445 thousand for Q1 2023. Operating costs
per boe amounted to USD 17.09 per boe in Q1 2024 below guidance for the quarter and compared with USD 17.31 per boe in Q1
2023.
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 45,206 thousand for Q1 2024 compared to USD 47,817 thousand for Q1 2023. The
decrease versus the comparative period is largely attributable to lower diluent pricing.
Change in inventory position
The Bertam field in Malaysia is located offshore and production is lifted and sold from the FPSO Bertam when a cargo parcel size
is reached. Accordingly, the timing of a lifting varies based on the inventory level on the FPSO facility and the change in inventory
position varies, both positively and negatively, from period to period. Inventories are valued at the lower of cost including depletion,
and market value, and the difference in the valuation between period ends is reflected in the change in inventory position in the
statement of operations. At the end of Q1 2024, IPC had crude entitlement of 279,000 barrels of oil on the FPSO Bertam facility
being crude produced but not yet sold. The next Bertam lifting occurred in April 2024.
Depletion and decommissioning costs
The total depletion of oil and gas properties amounted to USD 33,153 thousand for Q1 2024 compared to USD 6,439 thousand for
Q1 2023 (including an adjustment for accelerated decommissioning activities amounting to USD 24,178 thousand). The depletion
charge is analyzed in the following tables:
Three months ended – March 31, 2024
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands 9,744 13,160 7,030 3,219 33,153
USD per boe2 7.02 5.38 18.65 14.05 7.47
Three months ended – March 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Depletion cost in USD thousands1 9,353 12,302 5,829 3,133 30,617
USD per boe2 6.41 5.65 12.76 13.98 6.96
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 Q1 2024.
14
===== SIDA 36 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 2,262 thousand for Q1 2024 compared to USD 2,558 thousand for Q1
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 75 thousand for Q1 2024 and a cost of USD
1,609 thousand for the year ended December 31, 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 9,770 thousand for Q1 2024, compared to a charge of USD 5,015 thousand
for Q1 2023, and included a non-cash net foreign exchange loss of USD 2,061 thousand for Q1 2024 compared to a net foreign
exchange loss of USD 856 thousand for Q1 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 7,709 thousand for Q1 2024,
compared to USD 4,159 thousand for Q1 2023.
The interest expense amounted to USD 8,818 thousand for Q1 2024, compared to USD 5,349 thousand for the comparative period
in 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 5,617 thousand for Q1 2024 and is higher than the comparative period of USD 4,924 thousand
due mainly to higher interest rates and higher cash balances.
The unwinding of the asset retirement obligation discount rate amounted to USD 3,618 thousand for Q1 2024, compared to USD
3,068 thousand for the comparative period 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 7,746 thousand for Q1 2024, compared to a charge of USD 15,611
thousand for the comparative period.
The current income tax charge amounted to USD 1,373 thousand for Q1 2024 compared to USD 3,991 thousand for Q1 2023 and
mainly related to France and Malaysia. The current income tax charge for the comparative period included a provision for a windfall
profits tax amounting to USD 754 thousand in Q1 2023. 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 year ended December 31, 2023 was as follows:
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Development 99,809 10,295 14,200 790 125,094
Exploration and evaluation – – 162 – 162
99,809 10,295 14,362 790 125,256
During the first quarter of 2024, capital expenditure of USD 125,256 thousand was mainly spent in Canada on the Blackrod Phase
1 Development project and in Malaysia on the well workovers.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 23,117 thousand as at March 31, 2024, which included USD 21,468 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.
15
===== SIDA 37 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
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 March 31, 2024, IPC had
a nominal MUSD 450 of bonds outstanding with maturity in February 2027. The bond repayment obligations as at March 31, 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. No
cash amounts were drawn under the Canadian RCF as at March 31, 2024.
As at March 31, 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 March
31, 2024 was MUSD 8. An amount of MUSD 3.5 drawn under the France Facility as at March 31, 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 March 31, 2024.
Total net debt as at March 31, 2024 amounted to MUSD 61. Cash and cash equivalents held amounted to MUSD 397 as at March
31, 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 March 31, 2024, the Group had a working capital balance including cash of USD 352,306 thousand compared to USD
487,709 thousand as at December 31, 2023. The difference as at March 31, 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.
16
===== SIDA 38 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
“Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is
used to analyze the cash cost of producing the oil and gas volumes.
“Net debt” is calculated as bank loans and bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash
equivalents less bank loans and bonds.
Reconciliation of Non-IFRS Measures
Operating cash flow
The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended March 31
2024 2023
Revenue 206,419 192,516
Production costs (115,745) (117,527)
Current tax (1,373) (3,991)
Operating cash flow 89,301 70,998
The operating cash flow for the three months ended March 31, 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 75,900
thousand.
Free cash flow
The following table sets out how free cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended March 31
2024 2023
Operating cash flow - see above 89,301 70,998
Capital expenditures (125,256) (48,238)
Abandonment and farm-in expenditures1 (122) (1,211)
General, administration and depreciation expenses before depreciation2 (3,653) (3,811)
Cash financial items3 (3,581) (648)
Free cash flow (43,311) 17,090
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 three months ended March 31, 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 16,259
thousand.
17
===== SIDA 39 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended March 31
2024 2023
Net result 33,719 39,563
Net financial items 9,770 5,015
Income tax 7,746 15,611
Depletion and decommissioning costs 33,153 6,439
Depreciation of other tangible fixed assets 2,262 2,558
Exploration and business development costs 75 1,609
Depreciation included in general, administration and depreciation
expenses1 295 383
EBITDA 87,020 71,178
1 Item is not shown in the Financial Statements.
The EBITDA for the three months ended March 31, 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 76,079 thousand.
Operating costs
The following table sets out how operating costs is calculated:
USD Thousands
Three months ended March 31
2024 2023
Production costs 115,745 117,527
Cost of blending (45,206) (47,817)
Change in inventory position 5,277 5,735
Operating costs 75,816 75,445
The operating costs for three months ended March 31, 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 82,246
thousand.
Net cash/(debt)
The following table sets out how net cash/(debt) is calculated:
USD Thousands March 31, 2024 December 31, 2023
Bank loans (7,962) (9,031)
Bonds1 (450,000) (450,000)
Cash and cash equivalents 397,390 517,074
Net cash/(debt) (60,572) 58,043
1 The bond amount represents the redeemable value at maturity (February 2027).
18
===== SIDA 40 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, has issued four 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; and (d) MCAD 0.5 in relation to the hedging of electricity
prices.
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 March 31, 2024, IPC purchased and cancelled a total of 1,553,906 common shares under the
NCIB. As at March 31, 2024, IPC had a total of 125,438,160 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 March 31, 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 3,327,463 IPC Share Unit Plan awards outstanding as at May 7, 2024 (4,333 awards granted in January 2022, 1,090,117
awards granted in March 2022, 2,391 awards granted in July 2022, 2,072 awards granted in January 2023, 1,033,384 awards
granted in February 2023, 3,244 awards granted in July 2023, 2,443 awards granted in January 2024 and 1,189,479 awards
granted in February 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 March 31, 2024:
MCAD 2024 2025 2026 2027 2028 Thereafter
Transportation service 1 21.0 29.2 38.4 43.4 46.4 555.6
Power2 8.7 12.4 12.4 12.4 9.8 –
Total commitments 29.7 41.6 50.8 55.8 56.2 555.6
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 15MW at a weighted average price of CAD 74.92/MWh from April 1, 2024 to December 31,
2028 and an additional 5MW at a weighted average price of CAD 58.31/MWh from July 1, 2024 to December 31, 2027.
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 three months ended March 31, 2024, the Group paid USD 111 thousand to the Lundin Foundation in respect of
sustainability advisory services provided to the Group and USD 193 thousand to Orrön Energy in respect of office space rental for
the first quarter 2024.
During the three months ended March 31, 2024, Orrön Energy paid USD 168 thousand to the Group in respect of support services
provided to Orrön Energy during the first quarter 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.
19
===== SIDA 41 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
Financial Risk Management
As an international oil and gas exploration and production company, IPC is exposed to financial risks such as interest rate risk,
currency risk, credit risk, liquidity risks as well as the risk related to the fluctuation in oil and gas prices. The Group seeks to control
these risks through sound management practice and the use of internationally accepted financial instruments, such as oil and gas,
condensate and electricity price, interest rate or foreign exchange hedges as the case may be. Financial instruments will be solely
used for the purpose of managing risks in the business. As at March 31, 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 March 31, 2024, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
April 1, 2024 – December 31, 2024 17,700 WTI/WCS Differential USD -15.03/bbl
April 1, 2024 – December 31, 2024 8,250 WTI Sale Swap USD 80.01/bbl
The Group had electricity financial hedges outstanding as at March 31, 2024, which are summarized as follows:
Period Volume (MW) Type Average Pricing
October 1, 2025 - September 30, 2040 3 AESO CAD 75.00/MWh
The Group had no gas price sale financial hedges outstanding as at March 31, 2024.
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 11,496 thousand as at March 31, 2024.
In April 2024, the Group also entered into the following oil price sale financial hedges in Canada:
Period Volume (barrels per day) Type Average Pricing
April 1, 2024 - December 31, 2024 4,000 WTI Sale Swap USD 80.76/bbl
April 1, 2024 - December 31, 2024 3,000 Brent Sale Swap USD 85.50/bbl
20
===== SIDA 42 =====
Management’s Discussion and Analysis
For the three months ended March 31, 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 MCAD 20 per month at CAD 1.36 (sell USD) and
in Malaysia to buy MMYR 11.5 per month at MYR 4.63 (sell USD) in respect of 2024, and to buy MCAD 15 per month at
CAD 1.36 (sell USD) in respect of 2025, to partially meet forecast operational expenses in those countries. In respect of the forecast
Blackrod Phase 1 development capital expenditure in Canada, IPC entered into further currency hedges to purchase a total MCAD 556
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 2,574 thousand as at March 31, 2024.
In April 2024, IPC entered into currency hedge swaps from May 2024 to December 20024 to buy MEUR 2.5 per month, sell USD
at an average exchange rate of 1.0705.
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 three months period ended
March 31, 2024, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial
reporting.
Control Framework
Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control
– Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO).
21
===== SIDA 43 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
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;
• 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“.
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,
22
===== SIDA 44 =====
Management’s Discussion and Analysis
For the three months ended March 31, 2024
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.
23
===== SIDA 45 =====
Management’s Discussion and Analysis
For the three months ended March 31, 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
24
===== SIDA 46 =====
Management’s Discussion and Analysis
For the three months ended March 31, 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
March 31, 2024 24.9 7.9 96.0 MMcf
(16.0 Mboe) 48.8
March 31, 2023 26.6 9.5 99.9 MMcf
(16.7 Mboe) 52.8
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.
25
===== SIDA 47 =====
Management’s Discussion and Analysis
For the three months ended March 31, 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)
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.
26
===== SIDA 48 =====
Management’s Discussion and Analysis
For the three months ended March 31, 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
27
===== SIDA 49 =====
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□