FULLTEXT DEL 1 AV 2
Kvartalsrapport Q4 2023
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Q4
International Petroleum Corporation
Audited Consolidated Financial
Statements
For the years ended December 31, 2023 and 2022
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2
Contents
Report of Management 3
Report of Independent Auditor 4
Consolidated Statement of Operations 9
Consolidated Statement of Comprehensive Income 10
Consolidated Balance Sheet 11
Consolidated Statement of Cash Flow 12
Consolidated Statement of Changes in Equity 13
Notes to the Consolidated Financial Statements 14
Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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3
Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
REPORT OF MANAGEMENT
The accompanying consolidated financial statements of International Petroleum Corporation (“IPC” or the “Corporation” and,
together with its subsidiaries, the “Group”) and other information contained in the management’s discussion and analysis are
the responsibility of management and have been approved by the Board of Directors. The consolidated financial statements have
been prepared by management in accordance with IFRS Accounting Standards (“IFRS”) as issued by the International Accounting
Standards Board (“IASB”) as outlined in Part 1 of the Handbook of the Chartered Professional Accountants of Canada, and include
some amounts that are based on management’s estimates and judgment.
The Board of Directors carries out its responsibility for the consolidated financial statements principally through its Audit Com-
mittee, which is comprised solely of independent directors. The Audit Committee reviews the Group’s annual consolidated finan-
cial statements and recommends its approval to the Board of Directors. The Corporation’s auditors have full access to the Audit
Committee, with and without management being present. These consolidated financial statements have been audited by Pricewa-
terhouseCoopers SA, Chartered Professional Accountants, Licensed Public Accountants.
(Signed) William Lundin (Signed) Christophe Nerguararian
Director, President and Chief Executive Officer Chief Financial Officer
Vancouver, Canada
February 6, 2024
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Independent auditor’s report
To the Shareholders of International Petroleum Corporation
Our opinion
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects,
the financial position of International Petroleum Corporation and its subsidiaries (together, the
Corporation) as at December 31, 2023 and 2022 and its financial performance and its cash flows for the
years then ended in accordance with IFRS Accounting Standards (IFRS).
What we have audited
The Corporation’s consolidated financial statements comprise:
x the consolidated statements of operations for the years ended December 31, 2023 and 2022;
x the consolidated statements of comprehensive in come for the years ended December 31, 2023 and
2022;
x the consolidated balance sheet for the years ended December 31, 2023 and 2022;
x the consolidated statements of cash flow for the years then ended;
x the consolidated statements of changes in equity for the years then ended; and
x the notes to the consolidated financial statemen ts, which include significant accounting policies.
Basis for opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards. Our
responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of
the consolidated financial statements section of our report.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for
our opinion.
Independence
We are independent of the Corporation in accordance with the ethical requirements that are relevant to
our audit of the consolidated financial statements in Canada. We have fulfilled our other ethical
responsibilities in accordance with these requirements.
Key audit matter
Key audit matters are those matters that, in our professional judgement, were of most significance in our
audit of the consolidated financial statements for the year ended December 31, 2023. These matters
were addressed in the context of our audit of the consolidated financial statements as a whole, and in
forming our opinion thereon, and we do not provide a separate opinion on these matters.
PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland
Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch
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PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland
Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch
Key audit matter How our audit addressed the key audit matter
The impact of oil and gas reserves on net property, plant and
equipment (PP&E) for the Canada, Malaysia, and France
segments
Refer to note 1 - Corporate information, note 2 - Critical
accounting estimates and judgements, and note 8 – Oil and Gas
Properties to the consolidated financial statements.
The Corporation had USD 1’278.5 million of net PP&E assets as
at December 31, 2023. Depletion charges were USD 126.0 million
for the year then ended. PP&E is depleted based on the year’s
production in relation to the estimated total proved and probable
reserves in accordance with the unit of production method.
PP&E assets are grouped for recoverability assessment purposes
into cash generating units (CGU’s). At each balance sheet date or
when there are facts and circumstances that suggest that the net
book value of capitalized costs within each field area cost centre is
higher than anticipated future net cash flow from oil and gas
reserves attributable to the Corporation’s interest in the related
field areas, the Corporation performs an assessment as to
whether there is an indication that an asset may be impaired.
Management determines the recoverable amounts of the CGU
based on the higher of fair value less costs of disposal and value
in use using estimated future discounted net cash flows of proved
and probable oil and gas reserves. The Corporation’s estimates of
proved and probable oil and gas reserves used in the calculations
for impairment tests and accounting for depletion have been
reviewed by Management’s experts, specifically independent
qualified reserves evaluators.
Significant assumptions developed by management used to
determine the recoverable amount of the CGU’s include the
proved and probable oil and gas reserves, expected production
volumes, future oil and gas prices, future development costs,
future production costs and the discount rate.
We determined that this is a key audit matter due to (i) the
significant judgment made by management, including the use of
management’s experts, when developing the expected future cash
flows to determine the recoverable amount and the proved and
probable oil and gas reserves; and (ii) a high degree of auditor
judgment, subjectivity and effort in performing procedures
and evaluating audit evidence relating to management’s
estimates.
Our approach to addressing the matter included the
following procedures, among others:
භ The work of management’s experts was used in
performing the procedures to evaluate the
reasonableness of the proved and probable oil and
gas reserves used to determine depletion charges
and the recoverable amount of PP&E. As a basis
for using this work, management’s experts’
competence, capability and objectivity were
evaluated, their work performed was understood
and the appropriateness of their work as audit
evidence was evaluated by considering the
relevance and reasonableness of the
assumptions, methods and findings.
භ Tested how management determined the
recoverable amount of CGU’s, which included the
following:
o Evaluated the appropriateness of the methods
used by management in making these
estimates.
o Tested the data used in determining these
estimates.
o Evaluated the reasonableness of significant
assumptions used in developing the
underlying estimates:
ඵ Expected production volumes, future
development costs and future production
costs by considering the past
performance of each segment, and
whether these assumptions were
consistent with evidence obtained in
other areas of the audit.
ඵ Future oil and gas prices by comparing
those prices with other reputable third-
party industry forecasts.
ඵ The discount rate, by performing an
independent sensitivity analysis.
x Recalculated the unit of production rates used to
calculate depletion charges of PP&E.
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PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland
Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch
Other information
Management is responsible for the other information. The other information comprises the Management’s
Discussion and Analysis.
Our opinion on the consolidated financial statements does not cover the other information and we do not
express any form of assurance conclusion thereon.
In connection with our audit of the consolidated financial statements, our responsibility is to read the other
information identified above and, in doing so, consider whether the other information is materially
inconsistent with the consolidated financial statements or our knowledge obtained in the audit, or
otherwise appears to be materially misstated.
If, based on the work we have performed, we conclude that there is a material misstatement of this other
information, we are required to report that fact. We have nothing to report in this regard.
Responsibilities of management and those charged with governance for the
consolidated financial statements
Management is responsible for the preparation and fair presentation of the consolidated financial
statements in accordance with IFRS, and for such internal control as management determines is
necessary to enable the preparation of consolidated financial statements that are free from material
misstatement, whether due to fraud or error.
In preparing the consolidated financial statements, management is responsible for assessing the
Corporation’s ability to continue as going concern, disclosing, as applicable, matters related to going
concern and using the going concern basis of accounting unless management either intends to liquidate
the Corporation or to cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Corporation’s financial reporting
process.
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PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland
Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch
Auditor’s responsibilities for the audit of the consolidated financial statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as
a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s
report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a
guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards
will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and
are considered material if, individually or in the aggregate, they could reasonably be expected to influence
the economic decisions of users taken on the basis of these consolidated financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise
professional judgment and maintain professional skepticism throughout the audit. We also:
භ Identify and assess the risks of material misstat ement of the consolidated financial statements,
whether due to fraud or error, design and perform audit procedures responsive to those risks, and
obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of
not detecting a material misstatement resulting from fraud is higher than for one resulting from error,
as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of
internal control.
භ Obtain an understanding of internal control relevant to the audit in order to design audit procedures
that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the Corporation’s internal control.
භ Evaluate the appropriateness of accounting policies used and the reasonableness of accounting
estimates and related disclosures made by management.
භ Conclude on the appropriateness of management’s use of the going concern basis of accounting and,
based on the audit evidence obtained, whether a material uncertainty exists related to events or
conditions that may cast significant doubt on the Corporation’s ability to continue as a going concern.
If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s
report to the related disclosures in the consolidated financial statements or, if such disclosures are
inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to
the date of our auditor’s report. However, future events or conditions may cause the Corporation to
cease to continue as a going concern.
භ Evaluate the overall presentation, structure and content of the consolidated financial statements,
including the disclosures, and whether the consolidated financial statements represent the underlying
transactions and events in a manner that achieves fair presentation.
භ Obtain sufficient appropriate audit evidence regard ing the financial information of the entities or
business activities within the Corporation to express an opinion on the consolidated financial
statements. We are responsible for the direction, supervision and performance of the group audit. We
remain solely responsible for our audit opinion.
We communicate with those charged with governance regarding, among other matters, the planned scope
and timing of the audit and significant audit findings, including any significant deficiencies in internal
control that we identify during our audit.
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PricewaterhouseCoopers SA, avenue Giuseppe-Motta 50, case postale, CH-1211 Genève 2, Switzerland
Téléphone: +41 58 792 91 00, Téléfax: + 41 58 792 91 10, www.pwc.ch
From the matters communicated with those charged with governance, we determine those matters that
were of most significance in the audit of the consolidated financial statements of the current period and
are therefore the key audit matters. We describe these matters in our auditor’s report unless law or
regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we
determine that a matter should not be communicated in our report because the adverse consequences of
doing so would reasonably be expected to outweigh the public interest benefits of such communication.
We also provide those charged with governance with a statement that we have complied with relevant
ethical requirements regarding independence, and to communicate with them all relationships and other
matters that may reasonably be thought to bear on our independence, and where applicable, related
safeguards.
The engagement partner on the audit resulting in this independent auditor’s report is Colin Johnson.
PricewaterhouseCoopers SA
Colin Johnson Luc Schulthess
Chartered Professional Accountant
February 6, 2024
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9
Consolidated Statement of Operations
For the years ended December 31, 2023 and 2022, AUDITED
USD Thousands Note 2023 2022
Revenue 3 853,906 1,129,298
Cost of sales
Production costs 4 (491,303) (476,986)
Depletion and decommissioning costs 8 (101,922) (122,041)
Depreciation of other tangible fixed assets 10 (7,812) (10,787)
Exploration and business development costs (2,355) (2,775)
Gross profit 3 250,514 516,709
Sale of assets 8 19,018 –
General, administration and depreciation expenses (18,455) (14,440)
Profit before financial items 251,077 502,269
Finance income 5 21,774 6,999
Finance costs 6 (44,510) (44,130)
Net financial items (22,736) (37,131)
Profit before tax 228,341 465,138
Income tax expense 7 (55,362) (127,413)
Net result 172,979 337,725
Net result attributable to:
Shareholders of the Parent Company 172,951 337,683
Non-controlling interest 28 42
172,979 337,725
Earnings per share – USD1 17 1.31 2.30
Earnings per share fully diluted – USD1 17 1.28 2.25
1 Based on net result attributable to shareholders of the Parent Company
See accompanying notes to the consolidated financial statements
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Consolidated Statement of Comprehensive Income
For the years ended December 31, 2023 and 2022, AUDITED
USD Thousands Note 2023 2022
Net result 172,979 337,725
Other comprehensive income
Items that may be reclassified to profit or loss:
Reclassification of hedging gains losses to profit or
loss 3, 24 (18,928) (19,125)
Gains on cash flow hedges 48,786 28,819
Income tax relating to these items (7,051) (2,343)
Currency translation adjustments 20,994 (43,461)
Items that will not be reclassified to profit or loss:
Re-measurements on defined pension plan 21 (679) 3,778
Total comprehensive income 216,101 305,393
Total comprehensive income attributable to:
Shareholders of the Parent Company 216,076 305,359
Non-controlling interest 25 34
216,101 305,393
See accompanying notes to the consolidated financial statements
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Consolidated Balance Sheet
For the years ended December 31, 2023 and 2022, AUDITED
USD Thousands Note December 31, 2023 December 31, 2022
ASSETS
Non-current assets
Oil and gas properties 8 1,278,422 963,375
Other tangible fixed assets 10 25,438 33,374
Right-of-use assets 11 2,814 1,217
Deferred tax assets 7 1,827 1,960
Derivative instruments 23 7,049 –
Other assets 12 56,838 41,125
Total non-current assets 1,372,388 1,041,051
Current assets
Inventories 13 21,808 15,958
Trade and other receivables 14 113,497 123,609
Derivative instruments 23 35,504 11,741
Current tax receivables 2,714 18
Cash and cash equivalents 15 517,074 487,240
Total current assets 690,597 638,566
TOTAL ASSETS 2,062,985 1,679,617
LIABILITIES
Non-current liabilities
Financial liabilities 19 5,442 8,711
Bonds 19 435,041 295,440
Lease liabilities 11 2,087 507
Provisions 20 250,657 203,389
Deferred tax liabilities 7 86,348 56,334
Derivative instruments 23 263 –
Total non-current liabilities 779,838 564,381
Current liabilities
Trade and other payables 22 188,871 118,726
Financial liabilities 19 3,589 3,431
Derivative instruments 23 1,267 1,155
Current tax liabilities 255 17,793
Lease liabilities 11 809 752
Provisions 20 8,097 8,048
Total current liabilities 202,888 149,905
EQUITY
Shareholders’ equity 1,080,074 965,140
Non-controlling interest 185 191
Net shareholders’ equity 1,080,259 965,331
TOTAL EQUITY AND LIABILITIES 2,062,985 1,679,617
Approved by the Board of Directors
(Signed) C. Ashley Heppenstall (Signed) William Lundin
Director Director
See accompanying notes to the consolidated financial statements
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Consolidated Statement of Cash Flow
For the years ended December 31, 2023 and 2022, AUDITED
USD Thousands Note 2023 2022
Cash flow from operating activities
Net result 172,979 337,725
Adjustments for non-cash related items:
Depletion, depreciation and amortization 8,10,11 111,303 134,436
Gain on sale of assets (19,018) –
Income tax 7 55,362 127,413
Amortization of capitalized financing fees 6 342 2,228
Amortization of capitalized bonds fees 6 1,263 1,024
Foreign currency exchange 6 1,911 7,872
Interest expense 6 25,635 20,689
Interest income 5 (21,774) (6,966)
Unwinding of asset retirement obligation discount 6 13,408 10,758
Change in pension liability 21 446 542
Share-based costs 18 11,690 7,997
Other 2,998 1,209
Cash flow generated from operations (before
working capital adjustments and income taxes) 356,545 644,927
Changes in working capital 36,058 (13,305)
Decommissioning costs paid 20 (8,118) (5,809)
Other payments 20 (2,370) (2,736)
Income taxes received paid (34,868) (16,470)
Interest received 20,884 6,656
Interest paid (21,977) (11,445)
Net cash flow from operating activities 346,154 601,818
Cash flow used in investing activities
Investment in oil and gas properties 8 (312,729) (157,662)
Acquisition of Cor4 net of cash acquired 9 (59,419) –
Disposal of assets 9 20,191 –
Investment in other fixed assets 10 (510) (151)
Net cash (outflow) from investing activities (352,467) (157,813)
Cash flow from financing activities
Borrowings / (Repayments) 19 (3,111) (100,979)
Bonds issuance 137,550 300,000
Paid financing fees (507) (5,583)
Financing of Substantial Issuer Bid (“SIB”) 16 – (100,957)
Repurchase of own shares (“NCIB”) 16 (95,358) (80,578)
Other payments (980) (793)
Dividend paid (31) –
Net cash (outflow) from financing activities 37,563 11,110
Change in cash and cash equivalents 31,250 455,115
Cash and cash equivalents at the beginning of the
period 487,240 18,810
Currency exchange difference in cash and cash
equivalents (1,416) 13,315
Cash and cash equivalents at the end of the period 517,074 487,240
See accompanying notes to the consolidated financial statements
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Consolidated Statement of Changes in Equity
For the years ended December 31, 2023 and 2022, AUDITED
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 – 172,951 – – – – 172,951 28 172,979
Re-measurements on defined
pension plan – – – – – (679) (679) – (679)
Acquisition of Cor41 – – – – 881 – 881 – 881
Cash flow hedge – – – – 21,926 – 21’926 – 21’926
Currency translation difference – – 20,547 (83) 579 (46) 20,997 (3) 20,994
Total comprehensive income – 172,951 20’547 (83) 23,386 (725) 216,076 25 216,101
Dividend distribution – – – – – – – (31) (31)
Repurchase of own shares2 (95,358) – – – – – (95,358) – (95,358)
Share based costs – – – 13,535 – – 13,535 – 13,535
Share based payments3 (13,356) – – (5,963) – – (19,319) – (19,319)
Balance at December 31, 2023 230,005 808,846 (10,745) 18,838 31,344 1,786 1,080,074 185 1,080,259
1 See Note 9
2 See Note 16
3 The third instalment of IPC RSP 2020 awards, the second instalment of IPC RSP 2021 awards, the first instalment of IPC RSP 2022 awards and
the IPC PSP 2020 awards vested on January 31, 2023, at a price of CAD 14.26 per award. The difference between the value at vesting date
and at grant (respectively CAD 4.35 per award, CAD 4.07 per award, CAD 9.09 per award and CAD 3.65 per award) was offset against share
premium.
USD Thousands
Share
capital and
premium
Retained
earnings CTA IFRS 2
reserve
MTM
reserve
Pension
reserve Total
Non-
controlling
interest
Total
equity
Balance at January 1, 2022 528,764 298,212 11,291 9,700 874 (1,455) 847,386 157 847,543
Net result – 337,683 – – – – 337,683 42 337,725
Re-measurements on defined
pension plan – – – – – 3,778 3,778 – 3,778
Cash flow hedge – – – – 7,351 – 7,351 – 7,351
Currency translation difference – – (42,583) (791) (267) 188 (43,453) (8) (43,461)
Total comprehensive income – 337,683 (42,583) (791) 7,084 3,966 305,359 34 305,393
Repurchase of own shares1 (80,578) – – – – – (80,578) – (80,578)
Substantial Issuer Bid (“SIB”)1 (100,957) – – – – – (100,957) – (100,957)
Share based payments 2 (8,510) – – 2,440 – – (6,070) – (6,070)
Balance at December 31, 2022 338,719 635,895 (31,292) 11,349 7,958 2,511 965,140 191 965,331
1 See Note 16
2 The second instalment of IPC RSP 2020 awards and the first instalment of IPC RSP 2021 awards vested on February 28, 2022, at a price of CAD
8.93 per award. The difference between the value at vesting date and at grant (respectively CAD 4.35 per award and CAD 4.07 per award) was
offset against share premium. The third instalment of IPC RSP 2019 awards and the IPC PSP 2019 awards vested on June 30, 2022, at a price of
CAD 12.83 per award. The difference between the value at vesting date and at grant (respectively CAD 5.84 per award and CAD 4.28 per award)
was offset against share premium. See also Note 18.
See accompanying notes to the consolidated financial statements
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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 2000, 885 West Georgia Street, Vancouver, BC V6C 3E8, Canada.
On March 3, 2023, IPC completed the acquisition (the “Cor4 acquisition”) of all of the issued and outstanding shares of Cor4 Oil
Corp. (“Cor4”). On June 1, 2023, Cor4 was amalgamated into IPC Canada Ltd.
B. Basis of preparation
The consolidated financial statements have been prepared in accordance with IFRS Accounting Standards (“IFRS”) as issued by
the International Accounting Standards Board (“IASB”).
These consolidated financial statements are presented in United States Dollars (USD), which is the Group’s presentation and
functional currency. The 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.
These consolidated financial statements have been approved by the Board of Directors of IPC and authorized for issuance on
February 6, 2024.
C. Going concern
The Group’s consolidated financial statements for the year ended December 31, 2023, have been prepared on a going concern
basis, which assumes that the Group will be able to realize its assets and discharge its liabilities in the normal course of business
as they become due in the foreseeable future.
D. Changes in accounting policies and disclosures
During the year ended December 31, 2023, the Group applied the amended accounting standards, interpretations and annual
improvement points that are effective as of January 1, 2023. The application of the amendments did not have a material impact on
the consolidated financial statements.
There are no plans for the early adoption of published standards, interpretations, or amendments prior to their mandatory effective
date. The Group does not expect that other changes in IFRS will have a material impact on the consolidated financial statements.
E. Basis of Consolidation
Subsidiaries
Subsidiaries are all entities over which the Group has control and are consolidated. The Corporation controls an entity when it is
exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through
its power over the entity.
The non-controlling interest in a subsidiary represents the portion of the subsidiary not owned by Group companies. The equity of
the subsidiary relating to the non-controlling shareholders is shown as a separate item within changes in net equity.
Inter-company transactions, balances, income and expenses on transactions between companies are eliminated. Profits and losses
resulting from intercompany transactions that are recognized in assets are also eliminated.
F. Joint Arrangements
Oil and gas operations of the Group are conducted as co-licencees in unincorporated joint ventures with other companies and are
classified as joint operations. The consolidated financial statements reflect the relevant proportions of production, capital costs,
operating costs and current assets and liabilities of the joint operation applicable to the Corporation’s interests.
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
G. Foreign Currency Translation
Transactions and balances
Monetary assets and liabilities denominated in foreign currencies are translated at the rates of exchange prevailing at the balance
sheet date and foreign exchange currency differences are recognized in the consolidated statement of operations. Transactions
in foreign currencies are translated at exchange rates prevailing at the transaction date. Foreign exchange gains and losses are
presented within finance income and costs in the consolidated statement of operations.
Functional and presentation currency
Items included in the financial statements of each of the operational entities are measured using the currency of the primary
economic environment in which the entity operates (the “functional currency”). The functional currency of the Corporation’s
operational entities are the USD, CAD, MYR and EUR. The consolidated financial statements are presented in USD which is the
Corporation’s presentation currency. The balance sheets and income statements of foreign companies are translated using the
current rate method. All assets and liabilities are translated at the balance sheet date rates of exchange, whereas the income
statements are translated at average rates of exchange for the year, except for transactions where it is more relevant to use the
rate of the day of the transaction. The translation differences which arise are recorded directly in net assets.
Exchange rates for the relevant currencies of the Group with respect to the US Dollar are as follows:
December 31, 2023 December 31, 2022
Average Period end Average Period end
1 EUR equals USD 1.0816 1.1050 1.0539 1.0666
1 USD equals CAD 1.3496 1.3251 1.3015 1.3538
1 USD equals MYR 4.5598 4.5950 4.3995 4.4050
H. Classification of assets and liabilities
Non-current assets, long-term liabilities and provisions consist of amounts that are expected to be recovered or paid more than
twelve months after the balance sheet date. Current assets and current liabilities consist solely of amounts that are expected to be
recovered or paid within twelve months after the balance sheet date.
I. Oil and gas properties
Oil and gas properties are recorded at historical cost less depletion. All costs for acquiring concessions, licences or interests in
production sharing contracts and for the survey, drilling and development of such interests are capitalized on a field area cost
center basis.
Costs directly associated with an exploration well are capitalized until the determination of reserves is evaluated. If it is determined
that a commercial discovery has not been achieved, these exploration costs are charged to the income statement. During the
exploration and development phases, no depletion is charged. The field will be transferred from the non-producing assets to the
producing assets within oil and gas properties once production commences, and accounted for as a producing asset. Routine
maintenance and repair costs for producing assets are expensed to the income statement when they occur.
Property, plant and equipment are depleted based on the year’s production in relation to estimated total proved and probable
reserves of oil and gas in accordance with the unit of production method. Depletion of a field area is charged to the income
statement through cost of sales once production commences.
Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated
with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current
economic conditions, operating methods and governmental regulations. Proved reserves can be categorized as developed or
undeveloped. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence
that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the
quantities actually recovered will equal or exceed the estimates.
Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than
not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50 percent probability that
the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.
Proceeds from the sale or farm-out of oil and gas concessions in the exploration stage are offset against the related capitalized
costs of each cost center with any excess of net proceeds over the costs capitalized included in the income statement. In the
event of a sale in the exploration stage, any deficit is included in the income statement.
===== SIDA 16 =====
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
Impairment tests are performed annually or when there are indicators of impairment that suggest that the net book value of
capitalized costs within each field area cost center less any provision for asset retirement obligation costs is higher than the
anticipated future net cash flow from oil and gas reserves attributable to the Corporation’s interest in the related field areas.
Capitalized costs cannot be carried unless those costs can be supported by future cash flows from that asset. Provision is made
for any impairment, where the net carrying value, according to the above, exceeds the recoverable amount, which is the higher of
value in use and fair value less costs of disposal, determined through estimated future discounted net cash flows using prices and
cost levels used by management in their internal forecasting. If there is a decision to not continue with a field specific exploration
program, the costs will be expensed at the time the decision is made.
J. Other tangible fixed assets
Other tangible fixed assets are stated at cost less accumulated depreciation. The cost includes the original purchase price of the
asset and the costs attributable to bringing the asset to its working condition for its intended use. Depreciation is based on cost
and is calculated on a straight line basis over the estimated economic life of 3 to 5 years for office equipment and other assets.
The Floating Production Storage and Offloading (“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 production sharing contract
(“PSC“) expiry date, before the PSC extension to 2035.
Additional costs to existing assets are included in the assets’ net book value or recognized as a separate asset, as appropriate, only
when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be
measured reliably. The net book value of any replaced parts is written off. Other additional expenses are deemed to be repair and
maintenance costs and are charged to the income statement when they are incurred.
The net book value is written down immediately to its recoverable amount when the net book value is higher. The recoverable
amount is the higher of an asset’s fair value less cost of disposal and value in use. The assets’ residual values and useful lives are
reviewed, and adjusted if appropriate, at the end of each reporting period.
K. Leases
The Group leases various offices, warehouses, equipment and cars. Rental contracts are typically made for fixed periods of 3 to
5 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different
terms and conditions.
Right-of-use assets and corresponding liabilities are recognized when the leased asset is available for use by the Group. Each
lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the period so
as to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is
depreciated over the shorter of the asset’s useful life and the lease term on a straight-line basis.
Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present
value of the fixed and variable lease payments and the exercise price of the purchase option. The lease payments are discounted
using the incremental borrowing rate and are classified as finance leases. The right-of-use assets are measured at cost comprising
the amount of the initial measurement of the lease liability, any lease payments made and any initial direct costs.
Payments associated with short-term leases and leases of low-value assets are recognized on a straight-line basis as an expense
in profit or loss.
L. Impairment of Assets
At each balance sheet date or when there are facts and circumstances that suggest that the net book value of capitalized costs
within each field area cost center is higher than anticipated future net cash flow from oil and gas reserves attributable to the
Corporation’s interest in the related field areas, the Corporation performs an assessment as to whether there is an indication
that an asset may be impaired. Management determined the recoverable amounts of property, plant and equipment based on
the higher of fair value less costs of disposal and value in use using estimated future discounted net cash flows of proved and
probable oil and gas reserves. The Corporation’s estimates of proved and probable oil and gas reserves used in the calculations for
impairment tests and accounting for depletion have been reviewed by Management’s experts, specifically independent qualified
reserves auditor.
The recoverable amount is the higher of fair value less costs of disposal and value in use. In determining fair value less costs of
disposal, recent market transactions are considered, if available. In the absence of such transactions, an appropriate valuation
model is used. Value in use is calculated by discounting estimated future cash flows to their present value using a discount rate
that reflects current market assessments of the time value of money and the risks specific to the asset. When the recoverable
amount is less than the carrying value an impairment loss is recognized with the expensed charge to the income statement.
If indications exist that previously recognized impairment losses no longer exist or are decreased, the recoverable amount is
estimated. When a previously recognized impairment loss is reversed the carrying amount of the asset is increased to the
estimated recoverable amount but the increased carrying amount may not exceed the carrying amount after depreciation that
would have been determined had no impairment loss been recognized for the asset in prior years. If the asset does not generate
cash inflows that are largely independent of those from other assets or groups of assets, the asset is tested as part of a CGU,
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
which is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from
other assets or groups of assets. An impairment loss is the amount by which the carrying amount of the individual asset or CGU
exceeds its recoverable amount.
M. Financial Instruments
Financial assets and financial liabilities are recognized on the consolidated balance sheet on the trade date, the date on which
the Group becomes a party to the contractual provisions of the financial instrument. All financial instruments are required to
be classified and measured at fair value on initial recognition. Measurement in subsequent periods is dependent upon the
classification of the financial instrument. The Group classifies its financial instruments in the following categories:
Financial Assets at Amortized Cost
Assets that are held for collection of contractual cash flows where those cash flows represent solely payments of principal and
interest are measured at amortized cost. The Group’s loans and receivables consist of fixed or determined cash flows related
solely to principal and interest amounts or contractual sales of oil. The Group’s intent is to hold these receivables until cash flows
are collected. Loans and receivables are recognized initially at fair value, net of any transaction costs incurred and subsequently
measured at amortized cost.
Financial Assets at Fair Value through Profit or Loss (“FVTPL”)
Financial assets measured at FVTPL are assets which do not qualify as financial assets at amortized cost or at fair value through
other comprehensive income.
Financial Liabilities at Amortized Cost
Financial liabilities are measured at amortized cost, unless they are required to be measured at FVTPL, or the Group has opted
to measure them at FVTPL. Borrowings and accounts payable are recognized initially at fair value, net of any transaction costs
incurred, and subsequently at amortized cost using the effective interest method.
Financial Liabilities at FVTPL
Financial liabilities measured at FVTPL are liabilities which include embedded derivatives and cannot be classified as amortized
cost.
Impairment of Financial Assets
The measurement of impairment of financial assets is based on the expected credit losses model. For the trade and other
receivables, the Group applies the simplified approach which requires the use of the lifetime expected loss provision for all trade
receivables. In estimating the lifetime expected loss provision, the Group considered historical industry default rates as well as
credit ratings of major customers. Additional disclosure related to the Group’s financial assets is included in Note 23.
N. Derivative Financial Instruments and Hedging Activities
Derivatives are initially recognized at fair value on the date a derivative contract is entered into and are subsequently remeasured
to their fair value. The method of recognizing the resulting gain or loss depends on whether the derivative is designated as a
hedging instrument, and if so, the nature of the item being hedged. The Group designates certain derivatives as either hedges of a
particular risk associated with a recognized asset or liability or a highly probable forecasted transaction, hedges of the fair value of
recognized assets and liabilities or a firm commitment, or hedges of a net investment in a foreign operation.
The Group documents at the inception of the transaction the relationship between hedging instruments and the hedged items, as
well as its risk management objectives and strategy for undertaking various hedging transactions. The Group also documents its
assessment, both at hedge inception and on an ongoing basis, of whether the derivatives that are used in hedging transactions
are highly effective in offsetting changes in fair values or cash flows of the hedged items. The fair values of various derivative
financial instruments used for hedging purposes are disclosed in Note 23. Movements on the hedging reserve is reflected in other
comprehensive income. The full fair value of a hedging derivative is classified as a non-current asset or liability when the remaining
maturity of the hedged item is more than twelve months and as a current asset or liability when the remaining maturity of the
hedged item is less than twelve months.
Cash flow hedge
The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized
in other comprehensive income. The gain or loss relating to the ineffective portion, if any, is recognized immediately within finance
income or costs. Amounts accumulated in equity are reclassified to profit or loss in the periods when the hedged item affects
profit or loss. When a hedging instrument expires or is sold, or when a hedge no longer meets the criteria for hedge accounting,
any cumulative gain or loss existing in equity at that time remains in equity and is recognized when the forecast transaction is
ultimately recognized in the profit or loss. When a forecasted transaction is no longer expected to occur, the cumulative gain or
loss that was reported in equity is immediately recognized in profit or loss.
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O. Inventories
Inventories of consumable well supplies are stated at the lower of cost and net realizable value, cost being determined on a
weighted average cost basis. Net realizable value is the estimated selling price in the ordinary course of business, less applicable
variable selling expenses. Inventories of hydrocarbons are stated at the lower of cost and net realizable value. Under or overlifted
positions of hydrocarbons are valued at market prices prevailing at the balance sheet date. An underlift of production from a field
is included in the current receivables and valued at the reporting date spot price or prevailing contract price and an overlift of
production from a field is included in the current liabilities and valued at the reporting date spot price or prevailing contract price.
A change in the over or underlift position is reflected in the income statement as revenue.
P . Cash and cash equivalents
Cash and cash equivalents include cash at bank and cash in hand.
Q. Provisions
A provision is reported when the Group has a legal or constructive obligation as a consequence of a past event and when it is
more likely than not that an outflow of resources is required to settle the obligation and a reliable estimate can be made of the
amount.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a discount
rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in
the provision due to passage of time is recognized as financial expense.
On fields where there is an obligation to contribute to asset retirement obligation costs, a provision is recorded to recognize the
future commitment. An asset is created, as part of the oil and gas property, to represent the discounted value of the anticipated
asset retirement obligation liability and depleted over the life of the field on a unit of production basis. The corresponding
accounting entry to the creation of the asset recognizes the discounted value of the future liability. The discount applied to
the anticipated asset retirement obligation liability is subsequently released over the life of the field and is charged to financial
expenses. Changes in asset retirement obligation costs and reserves are treated prospectively and consistent with the treatment
applied upon initial recognition.
R. Revenue and Other Operating Revenue
Revenue associated with the sale of crude oil and natural gas is measured based on the consideration specified in a contract with
a customer and excludes amounts collected on behalf of third parties. The Group recognizes revenue when it transfers control of
the product or service to a customer, which is generally when title passes from the Group to its customer. The Group satisfies its
performance obligations in contracts with customers upon the delivery of crude oil and natural gas, which is generally at a point in
time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant.
Royalties payments to governments and other mineral interest owners are recognized as a cost in the revenue section.
Production and sales taxes directly attributable to fields, including export duties, are expensed in the income statement and
classified as direct production taxes included within production costs. Production taxes payable in cash are accrued in the
accounting period in which the liability arises.
S. Employee Benefits
Short-term employee benefits
Short-term employee benefits such as salaries, social premiums and holiday pay, are expensed when incurred.
Pension obligations
The pension obligations consist of defined contribution plans for all companies within the Group except for one Swiss subsidiary,
International Petroleum SA. A defined contribution plan is a pension plan under which the Group pays fixed contributions. The
Group has no further payment obligations once the contributions have been paid. The contributions are recognized as an expense
when they are due.
International Petroleum SA has a defined benefit pension plan that is managed through a private pension plan. Independent
actuaries determine the cost of the defined benefit plan on an annual basis, and the subsidiary pays the annual insurance premium.
The pension plan provides benefits coverage to the employees of International Petroleum SA in the event of retirement, death or
disability. International Petroleum SA and its employees jointly finance retirement and risk benefits. Employees of International
Petroleum SA pay 40% of the savings contributions, of the risk contributions and of the cost contributions and International
Petroleum SA contributes the difference between the total of all required pension plan contributions and the total of all employees’
contributions.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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19
Share-based payments
The Group operates an equity-settled, share-based compensation plan under which the entity receives services from employees,
directors and officers as consideration for equity instruments of the Corporation. Equity-settled share-based payments are
recognized in the income statement as expenses during the vesting period and as equity in the balance sheet. The option is
measured at fair value at the date of the grant using an appropriate options pricing model and is charged to the income statement
over the vesting period without revaluation of the value of the option.
T. Taxation
The components of tax are current and deferred. Tax is recognized in the income statement, except to the extent that it relates
to items recognized in other comprehensive income or directly in equity, in which case it is accounted for consistently with the
related item.
Current tax is tax that is to be paid or received for the year in question and also includes adjustments of current tax attributable to
previous periods.
Deferred income tax is a non-cash charge provided, using the liability method, on temporary differences arising between the
tax bases of assets and liabilities and their carrying values. Temporary differences can occur for example where investment
expenditure is capitalized for accounting purposes but the tax deduction is accelerated or where asset retirement obligation
costs are provided for in the financial statements but not deductible for tax purposes until they are actually incurred. However,
the deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a
business combination that at the time of the transaction affects neither accounting nor taxable profit nor loss.
Deferred income tax is provided on temporary differences arising on investments in subsidiaries and associates, except where the
timing of the reversal of the temporary difference is controlled by the Corporation and it is probable that the temporary difference
will not reverse in the foreseeable future. Deferred income tax is determined using tax rates (and laws) that have been enacted or
substantively enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realized
or the deferred income tax liability is settled. Deferred income tax assets are recognized to the extent that it is probable that future
taxable profit will be available against which the temporary differences can be utilized.
Deferred tax assets are offset against deferred tax liabilities in the balance sheet where they relate to the same jurisdiction and
there is a legally enforceable right to offset.
U. Segment Reporting
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker,
which, due to the unique nature of each country’s operations, commercial terms or fiscal environment, is at a country level.
V. Business combinations
Acquisitions of businesses are accounted for using the purchase method of accounting whereby all identifiable assets and
liabilities are recorded at their fair values as at the date of acquisition. Any excess purchase price over the aggregate fair value of
net assets is recorded as goodwill. Goodwill is identified and allocated to cash-generating units (“CGU”), or groups of CGUs, that
are expected to benefit from the synergies of the acquisition. Goodwill is not amortized. Any excess of the aggregate fair value of
net assets over the purchase price is recognized in the consolidated statement of operations.
A CGU to which goodwill has been allocated is tested for impairment at least annually or when events or circumstances indicate
that an assessment for impairment is required. For goodwill arising on an acquisition in a financial year, the CGU to which the
goodwill has been allocated is tested for impairment before the end of that financial year.
When the recoverable amount of the CGU is less than the carrying amount of that CGU, the impairment loss is allocated to
reduce the carrying amount of any goodwill allocated to that CGU first, and then to the other assets of that CGU pro rata on the
basis of the carrying amount of each asset in the CGU. Any impairment loss for goodwill is recognized directly in the consolidated
statement of earnings. An impairment loss for goodwill is not reversed in subsequent periods.
On disposal of a subsidiary, the attributable amount of goodwill is included in the determination of the gain or loss on disposal.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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2. CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS
In connection with the preparation of the consolidated financial statements, the Group’s management has made assumptions
and estimates about future events and applied judgments that affect the reported values of assets, liabilities, revenues, expenses
and related disclosures. The assumptions, estimates and judgments are based on historical experience, current trends and other
factors that management believes to be relevant at the time the consolidated financial statements are prepared. On a regular
basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that the consolidated
financial statements are presented fairly in accordance with IFRS. However, because future events and their effects cannot be
determined with certainty, actual results could differ from these assumptions and estimates, and such differences could be
material.
Management believes the following critical accounting policies affect the more significant judgments and estimates used in the
preparation of the consolidated financial statements:
Estimates in oil and gas reserves
Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and asset
retirement obligation. Standard recognized evaluation techniques are used to estimate the proved and probable reserves. These
techniques take into account the future level of development required to produce the reserves. An independent qualified reserves
auditor reviews these estimates. Changes in estimates in oil and gas reserves, resulting in different future production profiles, will
affect the discounted cash flows used in impairment testing, the anticipated date of site decommissioning and restoration and
the depletion charges in accordance with the unit of production method. Changes in estimates in oil and gas reserves could for
example result from additional drilling, observation of long-term reservoir performance or changes in economic factors such as oil
price and inflation rates.
Impairment of oil and gas properties
Key assumptions in the impairment models relate to prices and costs that are based on forward curves and the long-term
corporate assumptions. Annual impairment tests are performed in conjunction with the annual reserves certification process. The
impairment test requires the use of estimates. For the purpose of determining a potential impairment, the significant assumptions
developed by management used to determine the recoverable amount include the proved and probable oil and gas reserves,
expected production volumes, future oil and gas prices, future development costs, future production costs and the discount rate.
These assumptions and judgements of management that are based on them are subject to change as new information becomes
available. Changes in economic conditions can also affect the rate used to discount future cash flow estimates and the discount
rate applied is reviewed throughout the year.
Provision for asset retirement obligations
Amounts used in recording a provision for asset retirement obligations are estimates based on current legal and constructive
requirements and current technology and price levels for the removal of facilities and decommissioning. Due to changes in relation
to these items, the future actual cash outflows in relation to the site decommissioning and restoration can be different. To reflect
the effects due to changes in legislation, requirements and technology and price levels, the carrying amounts of asset retirement
obligation provisions are reviewed on a regular basis.
Deferred income tax assets
The Group accounts for differences that arise between the carrying amount of assets and liabilities and their tax bases in
accordance with IAS 12, Income Taxes, which requires deferred income tax assets only to be recognized to the extent that
is probable that future taxable profits will be available against which the temporary differences can be utilized. Management
estimates future taxable profits based on the financial models used to value its oil and gas properties. Any change to the estimates
and assumptions used for the key operational and financial variables used within the business models could affect the amount of
deferred income tax assets recognized.
The effects of changes in estimates do not give rise to prior year adjustments and are treated prospectively over the estimated
remaining commercial reserves of each field. While the Group uses its best estimates and judgement, actual results could differ
from these estimates.
Fair value of assets acquired and liabilities assumed in a business combination
The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and
any goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied
for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward
commodity prices, reserves and resources estimates, production costs and discount rates. Changes in these variables could
significantly impact the carrying value of the net assets.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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3. 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 8.
2023
USD Thousands Canada Malaysia France Other Total
Crude oil 688,891 101,237 81,093 – 871,221
NGLs 1,172 – – – 1,172
Gas 67,338 – – – 67,338
Net sales of oil and gas 757,401 101,237 81,093 – 939,731
Change in under/over lift position – – 400 – 400
Royalties (101,177) – (5,120) – (106,297)
Hedging settlement 18,928 – – – 18,928
Other operating revenue 7 – 867 270 1,144
Revenue 675,159 101,237 77,240 270 853,906
Operating costs (249,995) (35,679) (36,288) – (321,962)
Cost of blending (172,996) – – – (172,996)
Change in inventory position 504 3,358 (207) – 3,655
Depletion and decommissioning costs (70,104) (17,800) (14,018) – (101,922)
Depreciation of other tangible fixed assets – (7,812) – – (7,812)
Exploration and business development costs (834) – (39) (1,482) (2,355)
Gross profit/(loss) 181,734 43,304 26,688 (1,212) 250,514
2022
USD Thousands Canada Malaysia France Other Total
Crude oil 778,365 184,143 112,379 – 1,074,887
NGLs 774 – – – 774
Gas 154,754 – – – 154,754
Net sales of oil and gas 933,893 184,143 112,379 – 1,230,415
Change in under/over lift position – – (8,553) – (8,553)
Royalties (105,856) – (6,660) – (112,516)
Hedging settlement 19,125 – – – 19,125
Other operating revenue 111 – 716 – 827
Revenue 847,273 184,143 97,882 – 1,129,298
Operating costs (217,017) (35,051) (35,588) – (287,656)
Cost of blending (189,172) – – – (189,172)
Change in inventory position 1,038 (1,916) 720 – (158)
Depletion and decommissioning costs (75,077) (34,687) (12,277) – (122,041)
Depreciation of other tangible fixed assets – (10,787) – – (10,787)
Exploration and business development costs 97 – – (2,872) (2,775)
Gross profit/(loss) 367,142 101,702 50,737 (2,872) 516,709
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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USD Thousands
Assets Liabilities
2023 2022 2023 2022
Malaysia 175,816 251,059 48,743 34,573
France 204,006 209,088 95,840 120,095
Canada 1,966,370 1,246,105 1,082,035 560,709
Other 198,520 300,276 237,835 325,820
Intercompany balance elimination (481,727) (326,911) (481,727) (326,911)
Total Assets / Liabilities 2,062,985 1,679,617 982,726 714,286
Shareholders’ equity N/A N/A 1,080,074 965,140
Non-controlling interest N/A N/A 185 191
Total equity for the group N/A N/A 1,080,259 965,331
Total consolidated 2,062,985 1,679,617 2,062,985 1,679,617
4. PRODUCTION COSTS
USD Thousands 2023 2022
Cost of operations 275,868 245,360
Tariff and transportation expenses 40,929 36,873
Direct production taxes 5,165 5,423
Operating costs 321,962 287,656
Cost of blending1 172,996 189,172
Change in inventory position (3,655) 158
Total production costs 491,303 476,986
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.
5. FINANCE INCOME
USD Thousands 2023 2022
Interest income 21,774 6,966
Other financial income – 33
Total finance income 21,774 6,999
6. FINANCE COSTS
USD Thousands 2023 2022
Foreign exchange loss, net 1,911 7,872
Interest expense 25,635 20,689
Unwinding of asset retirement obligation discount 13,408 10,758
Amortization of loan fees 342 2,228
Amortization of bond fees 1,263 1,024
Loan commitment fees 672 537
Other financial costs 1,279 1,022
Total finance costs 44,510 44,130
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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7. INCOME TAX
USD Thousands 2023 2022
Current tax (14,457) (29,365)
Deferred tax (40,905) (98,048)
Total tax expense (55,362) (127,413)
In 2022, the current tax includes a windfall profits tax on energy companies applicable to the Group in France amounting to USD
10,915 thousand.
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 will come into effect from January 1, 2024. Since the Pillar Two legislation was not effective at
the reporting date, the Group has no related current tax exposure. 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. The Group is in the process of assessing its exposure to the Pillar Two legislation for when it comes into effect.
All relevant entities within the Group have an effective tax rate that exceeds 15% and as such the expected impact should be
insignificant.
The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the tax rate of Canada as follows:
USD Thousands 2023 2022
Profit before tax 228,341 465,138
Tax calculated at the corporate tax rate in Canada 25% (57,086) (116,284)
Effect of foreign and domestic tax rates 7,470 4,210
Tax effect of recognition / (derecognition) of unrecorded tax losses (4,736) (5,134)
Tax effect due to true-up of provision to prior year tax filings (102) 531
France Solidarity Contribution (windfall tax) – (10,915)
Other (908) 179
Total tax (55,362) (127,413)
Specification of deferred tax assets and tax liabilities1
USD Thousands 2023 2022
Unused tax loss carry forward 34,446 32,815
Other 5,959 5,841
Deferred tax assets 40,405 38,656
Accelerated allowances 115,399 90,400
Derivative hedges 9,527 2,630
Deferred tax liabilities 124,926 93,030
Deferred taxes, net (84,521) (54,374)
1 The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the
balance sheet when they relate to the same jurisdiction.
The deferred tax liabilities consist of accelerated allowances, being the difference between the book and the tax value of oil and
gas properties and site restoration provisions. The deferred tax liabilities will be released over the life of the oil and gas assets as
the book value is depleted for accounting purposes.
Deferred tax assets in relation to tax loss carried forwards are only recognized in so far that there is a reasonable certainty as to
the timing and the extent of their realization. The recognized unused tax loss carry forward mainly relates to Canada. The Group
has concluded that the deferred assets will be recoverable using the estimated future taxable income based on the approved
business plans and budgets.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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8. OIL AND GAS PROPERTIES
USD Thousands 2023 2022
Exploration and Evaluation Assets – 4,764
Property, Plant and Equipment 1,278,422 958,611
Oil and gas properties 1,278,422 963,375
Exploration and Evaluation Assets
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 – – – –
USD Thousands Canada Malaysia France Total
Cost
January 1, 2022 12,751 181 5,105 18,037
Additions1 (802) 149 4 (649)
Reclassification (11,974) (330) – (12,304)
Currency translation adjustments 25 – (345) (320)
Net book value December 31, 2022 – – 4,764 4,764
1 Net revenues on appraisal projects were being offset against capitalized costs of Exploration and Evaluation Assets.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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Property, Plant and Equipment
USD Thousands Canada Malaysia France Total
Cost
January 1, 2023 1,089,789 566,606 399,237 2,055,632
Acquisition of Cor4 - See Note 9 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 for gross proceeds of CAD 28.1 million (USD 20.8 million) and a net
accounting gain on disposal of CAD 25.7 million (USD 19.0 million).
2 In Canada, includes an adjustment in the first quarter of 2023 for accelerated decommissioning activities funded by a non-cash site rehabilitation
program.
USD Thousands Canada Malaysia France Total
Cost
January 1, 2022 1,021,944 534,443 408,211 1,964,598
Additions 118,762 27,305 12,244 158,311
Change in estimates 5,231 4,528 2,182 11,941
Reclassification 11,974 330 – 12,304
Currency translation adjustments (68,122) – (23,400) (91,522)
December 31, 2022 1,089,789 566,606 399,237 2,055,632
Accumulated depletion
January 1, 2022 (267,585) (450,347) (293,132) (1,011,064)
Depletion charge for the period (75,077) (34,687) (12,277) (122,041)
Currency translation adjustments 19,389 – 16,695 36,084
December 31, 2022 (323,273) (485,034) (288,714) (1,097,021)
Net book value December 31, 2022 766,516 81,572 110,523 958,611
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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Impairment test
The Group carried out its impairment testing at December 31, 2023, on a CGU basis in conjunction with the annual reserves
audit process. The Group used appropriate oil or natural gas price curves based on forward forecasts as at December 31, 2023,
a future cost inflation factor of 2% (2022: 2%) per annum, production and cost profiles based on proved and probable reserves
(2P reserves) as at December 31, 2023 and a discount rate of 10% (10% at December 31, 2022) to calculate the estimated future
post-tax cash flows.
The following prices were used in the impairment testing as at December 31, 2023:
Price Decks 2024 2025 2026 2027 2028
Average
annual
increase
thereafter
Dated Brent (USD/bbl) 80.00 80.00 80.00 81.60 83.23 2%
West Texas Intermediate (USD/bbl) 76.00 76.00 76.00 77.52 79.07 2%
Western Canadian Select (USD/bbl) 61.00 63.50 63.25 64.52 65.81 2%
AECO Gas (CAD/mcf) 2.33 3.64 3.95 4.03 4.11 2%
In 2023, as a result of the testing, no impairment of the oil and gas properties was required.
Sensitivities were calculated on the valuation of the estimated future post-tax cash flows. Using a discount rate of 12% instead of
10% or a USD 5/bbl decrease in the oil price curve or using a flat gas price curve at CAD 3.50/mcf did not result in an impairment
charge.
9. COR4 ACQUISITION
On March 3, 2023, IPC completed the acquisition of all of the issued and outstanding shares of Cor4. At such date, Cor4
became an indirect, wholly-owned subsidiary of IPC. Cor4 owned assets in the Brooks area, Alberta. On June 1, 2023, Cor4 was
amalgamated into IPC Canada Ltd.
The Cor4 acquisition has been accounted for as a business combination with IPC being the acquirer, and in accordance with IFRS
3 Business Combinations, the assets acquired and liabilities assumed have been recorded at their fair values.
The total cash consideration paid, after preliminary closing adjustments, amounted to USD 62.2 million (CAD 84.7 million).
The amounts recognized in respect of the identifiable assets acquired and liabilities assumed are as set out in the table below:
USD Thousands
Cash 2,792
Trade and other receivables 7,671
Prepaid expenses and deposits 2,417
Fair value of risk management assets 1,144
Deferred tax assets 19,334
Right-of-use assets 109
Property, plant and equipment 72,242
Accounts payable and accrued liabilities (12,623)
Right-of-use liabilities (109)
Decommissioning liabilities (29,885)
Mark-To-Market (“MTM”) reserve in equity (881)
Total Consideration 62,211
Settled by:
Cash payment 62,211
The Corporation performed a preliminary purchase price allocation for the Cor4 acquisition. The amounts disclosed above were
determined provisionally pending the finalization of the valuation for those assets and liabilities. Up to twelve months from the
effective date of the Cor4 acquisition, further adjustments may be made to the fair values assigned to the identifiable assets
acquired and liabilities assumed.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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27
Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during the year
ended December 31, 2023.
Decommissioning liabilities
The fair value of the decommissioning liability at the acquisition date was based on the estimated future cash flows to
decommission the acquired oil and natural gas properties at the end of their useful life. The discount rate used to determine the
net present value of the decommissioning obligation was a credit risk adjusted rate of 8%.
10. OTHER TANGIBLE FIXED ASSETS
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
USD Thousands FPSO Other Total
Cost
January 1, 2022 206,173 10,163 216,336
Additions – 151 151
Disposals – (44) (44)
Currency translation adjustments (1,320) (491) (1,811)
December 31, 2022 204,853 9,779 214,632
Accumulated depreciation
January 1, 2022 (162,524) (7,449) (169,973)
Depreciation charge for the period (10,787) (891) (11,678)
Disposals – 36 36
Currency translation adjustments – 357 357
December 31, 2022 (173,311) (7,947) (181,258)
Net book value December 31, 2022 31,542 1,832 33,374
The FPSO located on the Bertam field, Malaysia, is being depreciated on a unit of production basis using the Bertam field 2P
reserves to August 2025, being the original Bertam field PSC expiry date, before the PSC extension to 2035. The depreciation
charge is included in the depreciation of other assets line in the statement of operations.
For office equipment and other assets, the depreciation charge for the year is based on cost and an estimated useful life of 3 to
5 years. The depreciation charge is included within the general, administration and depreciation expenses in the Statement of
Operations.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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11. RIGHT-OF-USE ASSETS AND LEASE LIABILITIES
USD Thousands Buildings
January 1, 2023 1,217
Acquisition of Cor4 - See Note 9 109
Additions 2,508
Disposal (162)
Depreciation (885)
Currency translation adjustments 27
Right-of-use-assets as at December 31, 2023 2,814
Current 809
Non-Current 2,087
Lease Liabilities as at December 31, 2023 2,896
USD Thousands Buildings
January 1, 2022 1,639
Additions 393
Disposal (66)
Depreciation (717)
Currency translation adjustments (32)
Right-of-use-assets as at December 31, 2022 1,217
Current 752
Non-Current 507
Lease Liabilities as at December 31, 2022 1,259
12. OTHER NON-CURRENT ASSETS
USD Thousands December 31, 2023 December 31, 2022
Financial assets 41,486 35,882
Intangible assets 15,352 5,243
56,838 41,125
Financial assets mainly represent cash payments made to an asset retirement obligation fund for the Bertam field, Malaysia
for an amount of USD 28.7 million (2022: USD 28.2 million). In 2023, an amount of USD 1.8 million (2022: USD 1.9 million) was
paid into the asset retirement obligation fund which is held in local currency. (Also see Note 20.) 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. An amount of USD 9.4 million (CAD 12.5 million) carbon
offsets has been purchased in 2023.
13. INVENTORIES
USD Thousands December 31, 2023 December 31, 2022
Hydrocarbon stocks 13,530 8,988
Well supplies and operational spares 8,278 6,970
21,808 15,958
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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14. TRADE AND OTHER RECEIVABLES
USD Thousands December 31, 2023 December 31, 2022
Trade receivables 97,264 112,696
Underlift 1,029 599
Joint operations debtors 910 982
Prepaid expenses and accrued income 10,986 6,585
Other 3,308 2,747
113,497 123,609
15. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include only cash at hand or held in bank accounts.
16. SHARE CAPITAL
The Corporation’s issued common share capital is as follows:
Number of shares
Balance at January 1, 2022 155,198,105
Cancellation of repurchased common shares (10,112,042)
Cancellation following the Substantial Issuer Bid (8,258,064)
Balance at December 31, 2022 136,827,999
Cancellation of repurchased common shares (NCIB) (9,835,933)
Balance at December 31, 2023 126,992,066
The common shares of IPC are listed to trade on both the Toronto Stock Exchange and the Nasdaq Stockholm Exchange.
As at January 1, 2022, IPC had a total of 155,198,105 common shares issued and outstanding, of which IPC held 1,160,651
common shares in treasury. All common shares held in treasury as at January 1, 2022 were cancelled during January 2022.
During 2022, under the normal course issuer bid/share repurchase program announced in December 2021 and renewed in
December 2022 (NCIB), IPC purchased and cancelled an aggregate of 8,951,391 common shares.
During Q2 2022, IPC commenced an offer to repurchase common shares under the substantial issuer bid (SIB). Under the SIB,
IPC purchased and cancelled an aggregate of 8,258,064 common shares.
As at December 31, 2022, IPC had a total of 136,827,999 common shares issued and outstanding, with no common shares held in
treasury.
Over the period of December 5, 2022 to December 4, 2023, IPC purchased and cancelled a total of 9,333,479 common shares
under the NCIB (8,603,179 common shares purchased and cancelled in 2023). The NCIB was further 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.
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 Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
17. 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.
2023 2022
Net result attributable to shareholders of the Parent Company, USD 172,951,130 337,682,813
Weighted average number of shares for the period 132,080,662 146,662,032
Earnings per share, USD 1.31 2.30
Weighted average diluted number of shares for the period 135,349,211 149,976,365
Earnings per share fully diluted, USD 1.28 2.25
18. SHARE BASED PAYMENTS
IPC Share Unit Plan
The shareholders of IPC at the 2018 Annual General Meeting and at the 2021 Annual General Meeting approved a Share Unit Plan.
Awards under the plan will be accounted from the date of grant.
The IPC Performance Share Plan (“PSP”) 2020 awards vested on February 1, 2023 at a price of CAD 14.26 per award.
The IPC PSP 2021 awards are subject to continued employment and to certain performance conditions being met. The total
outstanding number of awards at December 31, 2023, is 1,716,000 which vest on February 1, 2024. Each award was fair valued
at the grant date at CAD 3.61 using an adjusted share price calculated with a hybrid valuation model based on the Monte Carlo
simulation. The assumptions used in the calculation of the adjusted share price were a risk free rate of 0.45%, expected volatility
of 68%, dividend yield rate of 0%, and an exercise price of CAD zero.
The IPC PSP 2022 awards are subject to continued employment and to certain performance conditions being met. The total
outstanding number of awards at December 31, 2023, is 937,000 which vest on February 1, 2025. Each award was fair valued
at the grant date at CAD 8.40 using an adjusted share price calculated with a hybrid valuation model based on the Monte Carlo
simulation. The assumptions used in the calculation of the adjusted share price were a risk free rate of 0.38%, expected volatility
of 45%, dividend yield rate of 0%, and an exercise price of CAD zero.
The IPC PSP 2023 awards are subject to continued employment and to certain performance conditions being met. The total
outstanding number of awards at December 31, 2023, is 813,000 which vest on February 1, 2026. Each award was fair valued
at the grant date at CAD 11.51 using an adjusted share price calculated with a hybrid valuation model based on the Monte Carlo
simulation. The assumptions used in the calculation of the adjusted share price were a risk free rate of 2.17%, expected volatility
of 46%, dividend yield rate of 0%, and an exercise price of CAD zero.
IPC Performance Share Plan 2020 Awards 2021 Awards 2022 Awards 2023 Awards Total
Outstanding at January 1, 2023 1,017,105 1,716,000 937,000 – 3,670,105
Awarded during the period – – – 813,000 813,000
Forfeited during the period – – – – –
Vested during the period (1,017,105) – – – (1,017,105)
Outstanding at December 31, 2023 – 1,716,000 937,000 813,000 3,466,000
Vesting date
February 1, 2024 – 1,716,000 – – 1,716,000
February 1, 2025 – – 937,000 – 937,000
February 1, 2026 – – – 813,00 813,000
Outstanding at December 31, 2023 – 1,716,000 937,000 813,000 3,466,000
The last third of the IPC Restricted Share Plan (“RSP”) 2020 awards vested on February 1, 2023, at a price of CAD 14.26 per
award.
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
The second third of the IPC RSP 2021 awards vested on February 1, 2023, at a price of CAD 14.26 per award. The total
outstanding number of 2021 awards under the IPC RSP as at December 31, 2023, is 321,512 which vest on February 1, 2024,
subject to continued employment. Each award was fair valued at the grant date at CAD 4.07.
The first third of the IPC RSP 2022 awards vested on February 1, 2023, at a price of CAD 14.26 per award. The total outstanding
number of 2021 awards under the IPC RSP as at December 31, 2023, is 307,359 which vest over two years on each of February 1,
2024 and February 1, 2025, subject to continued employment. Each award was fair valued at the grant date at CAD 9.09.
The total outstanding number of IPC RSP 2023 awards as at December 31, 2023, is 330,708 which vest over three years as to
one-third on each of February 1, 2024, February 1, 2025, and February 1, 2026, subject to continued employment. Each award was
fair valued at the grant date at CAD 14.27.
IPC Restricted Share Plan 2020 Awards 2021 Awards 2022 Awards 2023 Awards Total
Outstanding at January 1, 2023 199,304 674,225 484,534 – 1,358,063
Awarded during the period – – – 330,708 330,708
Forfeited during the period (792) (17,044) (16,294) – (34,130)
Vested during the period (198,512) (335,669) (160,881) – (695,062)
Outstanding at December 31, 2023 – 321,512 307,359 330,708 959,579
Vesting date
February 1, 2024 – 321,512 153,679 110,236 585,427
February 1, 2025 – – 153,680 110,236 263,916
February 1, 2026 – – – 110,236 110,236
Outstanding at December 31, 2023 – 321,512 307,359 330,708 959,579
Under the IPC Share Unit Plan, the Group allows non-employee directors of the Corporation to elect for awards for fees for
services performed as a director and otherwise payable in cash. These awards will vest immediately at the time of grant. However,
these awards may not be redeemed before the end of service as a director of the Corporation. The 2021 outstanding RSP awards
as at December 31, 2023 is 4,333 awards issued with a fair value at the grant date at CAD 6.95. The 2022 outstanding RSP awards
as at December 31, 2023 is 2,391 awards issued with a fair value at the grant date at CAD 12.80, and 2,072 awards issued with
a fair value at the grant date at CAD 15.53. The 2023 outstanding RSP awards as at December 31, 2023 is 3,244 awards issued
with a fair value at the grant date at CAD 10.52, and 2,443 awards issued with a fair value at the grant date at CAD 16.24. The total
outstanding RSP awards outstanding as at December 31, 2023, is 14,483.
In 2023, 10,703 awards issued in 2019, 46,551 awards issued in 2020, 18,277 awards issued in 2021, and 3,096 awards issued in
2022 have been exercised at a price of CAD 12.94.
The costs charged to the statement of operations of the Group for the Share-Based payments are summarized in the following
table:
USD Thousands 2023 2022
IPC PSP – 2019 Awards – 488
IPC RSP – 2019 Awards – 90
IPC PSP – 2020 Awards 159 984
IPC RSP – 2020 Awards 35 252
IPC PSP – 2021 Awards 1,881 1,712
IPC RSP – 2021 Awards 377 981
IPC PSP – 2022 Awards 2,856 1,721
IPC RSP – 2022 Awards 1,063 1,769
IPC PSP – 2023 Awards 3,360 –
IPC RSP – 2023 Awards 1,959 –
11,690 7,997
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
19. FINANCIAL LIABILITIES
USD Thousands December 31, 2023 December 31, 2022
Bank loans 9,031 12,142
Bonds 440,288 300,000
Capitalized financing fees (5,247) (4,560)
444,072 307,582
As at January 2022, the Group had a reserve-based lending (RBL) credit facility of USD 140 million in connection with its oil and
gas assets in France and Malaysia and a RBL credit facility of CAD 300 million in connection with its oil and gas assets in Canada.
In February 2022, IPC completed the issuance of USD 300 million of bonds, which mature in February 2027 and have a fixed
coupon rate of 7.25% per annum, payable in semi-annual instalments in August and February. The Group used a portion of the
proceeds of the bonds to fully repay the outstanding RBL credit facilities, which were then cancelled. At the same time, the Group
entered into a revolving credit facility of CAD 75 million (the “Canadian RCF”) in connection with its oil and gas assets in Canada.
In 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
December 31, 2023, IPC had a nominal USD 450 million of bonds outstanding with maturity in February 2027.
In Q1 2023, the Group increased the Canadian RCF to CAD 150 million and extended the maturity to May 2025. In Q3 2023, the
Group further increased the Canadian RCF to CAD 165 million and in Q4 2023, the Group further increased the Canadian RCF to
CAD 180 million. No cash amounts were drawn under the Canadian RCF as at December 31, 2023.
The bond repayment obligations as at December 31, 2023, are classified as non-current as there are no mandatory repayments
within the next twelve months.
As at December 31, 2023, IPC had a EUR 13 million unsecured credit facility in France (the “France Facility“), with maturity in May
2026. IPC commenced quarterly repayments of the French Facility in August 2022. The amount remaining outstanding
under the France Facility as at December 31, 2023 was USD 9 million (EUR 8 million).
An amount of USD 3.6 million (EUR 3.2 million) drawn under the France Facility as at December 31, 2023 is classified as current
representing the repayment planned within the next twelve months.
The Group is in compliance with the covenants of the bonds and its financing facilities as at December 31, 2023.
The net cash reconciliation can be summarized as follows:
USD Thousands December 31, 2023 December 31, 2022
Cash and cash equivalents 517,074 487,240
Bonds (440,288) (300,000)
Borrowings (9,031) (12,142)
Lease liabilities (2,896) (1,259)
Net cash 64,859 173,839
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
The net (debt)/cash and the movements in net (debt)/cash can be summarized as follows:
USD Thousands Cash Lease
liabilities
Financial
liabilities due
before 1 year
Financial
liabilities due
after 1 year
Bonds due
after 1 year Total
Net (debt)/cash as at January 1, 2023 487,240 (1,259) (3,431) (8,711) (300,000) 173,839
Cash flows 31,250 980 – 3,111 (140,288) (104,947)
Reclassification Long term / Short term – – (158) 158 – –
Additional leases – (2,651) – – – (2,651)
Currency translation adjustments (1,416) 34 – – – (1,382)
Net (debt)/cash as at December 31, 2023 517,074 (2,896) (3,589) (5,442) (440,288) 64,859
Net cash (excluding lease liabilities and
including the redeemable bonds value
at maturity (USD 450 million))
58,043
USD Thousands Cash Lease
liabilities
Financial
liabilities due
before 1 year
Financial
liabilities due
after 1 year
Bonds due
after 1 year Total
Net (debt)/cash as at January 1, 2022 18,810 (1,664) (1,806) (111,315) – (95,975)
Cash flows 455,115 793 – 100,979 (300,000) 256,887
Reclassification Long term / Short term – – (1,625) 1,625 – –
Additional leases – (393) – – – (393)
Currency translation adjustments 13,315 5 – – – 13,320
Net (debt)/cash as at December 31, 2022 487,240 (1,259) (3,431) (8,711) (300,000) 173,839
Net cash (excluding lease liabilities) 175,098
20. PROVISIONS
USD Thousands
Asset
retirement
obligation
Farm-in
obligation
Pension
obligation Other Total
January 1, 2023 206,249 3,404 306 1,478 211,437
Acquisition of Cor4 - See Note 9 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 for gross proceeds of CAD 28.1 million (USD 20.8 million) and a net
accounting gain on disposal of CAD 25.7 million (USD 19.0 million).
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 12).
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
USD Thousands
Asset
retirement
obligation
Farm-in
obligation
Pension
obligation Other Total
January 1, 2022 196,362 4,199 4,448 1,357 206,366
Additions – – 542 1,034 1,576
Unwinding of asset retirement obligation discount 10,758 – – – 10,758
Changes in estimates 11,375 567 (3,778) – 8,164
Payments (5,809) (1,153) (718) (865) (8,545)
Reclassification 1 1,909 – – – 1,909
Currency translation adjustments (8,346) (209) (188) (48) (8,791)
December 31, 2022 206,249 3,404 306 1,478 211,437
Non-current 199,335 2,270 306 1,478 203,389
Current 6,914 1,134 – – 8,048
Total 206,249 3,404 306 1,478 211,437
1 The reclassification of the asset retirement obligation related to the 2022 payment to the asset retirement obligation fund in respect of the Bertam
asset, Malaysia (see Note 12).
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% (2022: 6%) per annum was used,
based on a credit risk adjusted rate.
21. PENSION LIABILITY
The Group operates a pension plan for employees in Switzerland that is managed through a private pension plan. The amount
recognized in the balance sheet associated with the Swiss pension plan is as follows:
USD Thousands December 31, 2023 December 31, 2022
Present value of defined benefit obligation 22,241 13,910
Fair value of plan assets (21,690) (13,604)
Pension obligation, ending balance 551 306
The movement in the defined benefit obligation over the year is as follows:
USD Thousands For the year ended
December 31, 2023
For the year ended
December 31, 2022
Opening balance 13,910 14,714
Current service cost 423 596
Ordinary contributions paid by employees 617 479
Additional contributions paid by employees 6,685 2,291
Interest expense on defined benefit obligation 322 28
Actuarial (gain)/loss on defined benefit obligation 524 (3,706)
Administration costs 16 13
Benefits paid from plan assets (2,135) (232)
Past service cost – (75)
Foreign exchange (gain)/loss 1,879 (198)
Defined benefit obligation, ending balance 22,241 13,910
The weighted average duration of the defined benefit obligation is 15.2 years. There is no maturity profile since the average
remaining life before active employees reach final age according to the plan is 9.3 years.
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35
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
The movement in the fair value of the plan assets over the year is as follows:
USD Thousands For the year ended
December 31, 2023
For the year ended
December 31, 2022
Opening balance 13,604 10,266
Ordinary contributions paid by employer 925 718
Ordinary contributions paid by employees 617 479
Additional contributions paid by employees 6,685 2,291
Interest income on plan assets 315 20
Return on plan assets excluding interest income (155) 71
Foreign exchange gain/(loss) 1,834 (9)
Benefits paid from plan assets (2,135) (232)
Fair value of plan assets, ending balance 21,690 13,604
The plan assets are under an insurance contract comprised entirely of free funds and reserves, such as fluctuation reserves and
employer contribution reserves, for which there is no quoted price in an active market.
The amount recognized in the income statement associated with the Group’s pension plan is as follows:
USD Thousands For the year ended
December 31, 2023
For the year ended
December 31, 2022
Current service cost 423 596
Interest expense on defined benefit obligation 322 28
Administration costs 16 13
Past service cost – (75)
Interest income on plan assets (315) (20)
Total expense recognized 446 542
The expense associated with the Group’s pension plan of USD 446 thousand was included within general and administrative
expenses. The Group also recognized in other comprehensive income a USD 679 thousand net actuarial loss on defined benefit
obligations and pension plan assets.
The principal actuarial assumptions used to estimate the Group’s pension obligation are as follows:
USD Thousands For the year ended
December 31, 2023
For the year ended
December 31, 2022
Discount rate 1.90% 2.25%
Inflation rate 1.25% 1.25%
Future salary increase 1.25% 1.25%
Future pension increases 0.00% 0.00%
Retirement ages, male (‘M’) and female (‘F’) M65/F64 M65/F64
Assumptions regarding future mortality are set based on actuarial advice in accordance with the BVG 2020 GT generational
published statistics and experience in Switzerland. The discount rate is determined by reference to the yield on high quality
corporate bonds. The rate of inflation is based on the expected value of future annual inflation adjustments in Switzerland. The rate
for future salary increases is based on the average increase in the salaries paid by the Group, and the rate of pension increases is
based on the annual increase in risk, retirement and survivors’ benefits.
The sensitivity of the defined benefit obligation to changes in the weighted principal assumptions is:
Change in
assumption
Increase in
assumption
Decrease in
assumption
Discount rate 0.50% Decrease by 6.9% Increase by 7.8%
Salary growth rate 0.50% Increase by 0.2% Decrease by 0.3%
Life Expectancy One year Increase by 1.1% Decrease by 1.1%
The above sensitivity analyses are based on a change in an assumption while holding all other assumptions constant. In practice,
this is unlikely to occur, and changes in some of the assumptions may be correlated. When calculating the sensitivity of the
defined benefit obligation to significant actuarial assumptions, the same method has been applied as when calculating the pension
liability recognized within the consolidated balance sheet.
===== SIDA 36 =====
36
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
22. TRADE AND OTHER PAYABLES
USD Thousands December 31, 2023 December 31, 2022
Trade payables 42,761 20,547
Joint operations creditors 22,257 14,348
Accrued expenses 118,912 78,206
Other 4,941 5,625
188,871 118,726
23. FINANCIAL ASSETS AND LIABILITIES
Financial assets and liabilities by category
The accounting policies for financial instruments have been applied to the line items below:
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
1 See Note 12
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
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
December 31, 2022
USD Thousands
Total
Financial assets
at amortized
cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Other assets1 35,882 35,882 – –
Derivative instruments 11,741 – – 11,741
Joint operation debtors 982 982 – –
Other current receivables2 116,060 115,461 599 –
Cash and cash equivalents 487,240 487,240 – –
Financial assets 651,905 639,565 599 11,741
1 See Note 12
2 Prepayments are not included in other current assets as prepayments are not deemed to be financial instruments.
===== SIDA 37 =====
37
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
December 31, 2022
USD Thousands
Total
Financial
liabilities at
amortized cost
Fair value
recognized in
profit or loss
(FVTPL)
Derivatives
used for
hedging
Non-current financial liabilities 304,151 304,151 – –
Current financial liabilities 3,431 3,431 – –
Derivative instruments 1,155 – – 1,155
Joint operation creditors 14,348 14,348 – –
Other current liabilities 122,171 122,171 – –
Financial liabilities 445,256 444,101 – 1,155
The carrying amount of the Group’s financial assets approximate their fair values at the balance sheet dates.
For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
– Level 1: based on quoted prices in active markets;
– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
– Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
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
December 31, 2022
USD Thousands Level 1 Level 2 Level 3
Other current receivables 599 – –
Derivative instruments – current – 11,741 –
Financial assets 599 11,741 –
Derivative instruments – current – 1,155 –
Financial liabilities – 1,155 –
24. MANAGEMENT OF FINANCIAL RISK
The Corporation’s financial instruments are exposed to certain financial risks, including credit risk, liquidity risk, foreign exchange
risk, commodity price risk and interest rate risk.
a) Credit risk
The exposure to credit risk arises through the failure of a customer or another third party to meet its contractual obligations to the
Corporation. The Corporation believes that its maximum exposure to credit risk as at December 31, 2023, is the carrying value of
its trade receivables. The Group’s policy is to limit credit risk by limiting the counterparties to major oil and gas companies. Where
it is determined that there is a credit risk for oil and gas sales, the policy is to require an irrevocable letter of credit for the full value
of the sale. The policy on joint operation parties is to rely on the provisions of the underlying joint operating agreements to take
possession of the licence or the partner’s share of production for non-payment of cash calls or other amounts due.
As at December 31, 2023, the trade receivables amounted to USD 97,264 thousand and there is no recent history of default. The
expected credit loss associated with these receivables is not significant. Cash and cash equivalents are maintained with banks
having strong long-term credit ratings.
===== SIDA 38 =====
38
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
b) Liquidity risk
Liquidity risk is defined as the risk that the Group could not be able to settle or meet its obligations on time or at a reasonable
price. Corporation treasury is responsible for liquidity, funding as well as settlement management. The Corporation has in
place a planning and forecasting process to help determine the funds required to support the Corporation’s normal operating
requirements on an ongoing basis. The Corporation ensures that there is sufficient available capital to meet its short-term business
requirements, taking into account its anticipated cash flows from operations and its holdings of cash and cash equivalents,
including bond proceeds. The Corporation has credit facilities in place to assist with meeting its cash flow needs as required (Note
19).
The table below analyses the Group’s financial liabilities into relevant maturity groupings based on the remaining period at the
balance sheet date to the contractual maturity date. Loan repayments are made upon a net present value calculation of the assets’
future cash flows. No loan repayments are currently forecast under this calculation.
USD Thousands December 31, 2023 December 31, 2022
Non-current
Repayment within 1- 5 years:
- Bank loans 5,442 8,711
- Bonds1 440,288 300,000
445,730 308,711
Current
Repayment within 12 months:
- Bank loans 3,589 3,431
Repayment within 6 months:
- Trade payables 42,761 20,547
- Joint operation creditors 22,257 14,348
- Other current liabilities 4,941 5,625
- Current tax liabilities 255 17,793
73,803 61,744
1 The bonds redeemable value at maturity in February 2027 is USD 450 million.
c) Foreign exchange risk
The Group operates internationally and is exposed to foreign exchange risk arising from various currencies, primarily with respect
to EUR and CAD. The Group’s risk management objective is to manage cash flow risk related to foreign denominated cash flows.
The Corporation is exposed to currency risk related to changes in rates of exchange between foreign denominated balances and
the functional currencies of the Group’s principal operating subsidiaries. The Group’s revenues are denominated in US dollars,
while most of its operating and capital expenditures are denominated in the local currencies. A significant change in the currency
exchange rates between the US dollar and foreign currencies could have a material effect on the Group’s net earnings and on other
comprehensive income.
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).
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
===== SIDA 39 =====
39
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
The outstanding derivative instruments can be specified as follows:
Fair value of outstanding derivative instruments in the balance sheet
USD Thousands
December 31, 2023 December 31, 2022
Assets Liabilities Assets Liabilities
Currency hedge - CAD 13,644 1,328 1,084 –
Currency hedge - MYR 618 – 2,886 –
Total 14,262 1,328 3,970 –
Non-current 7,049 61 – –
Current 7,213 1,267 3,970 –
Total 14,262 1,328 3,970 –
The following tables summarize the effects that changes in currencies against the US Dollar would have on operating result and
equity through the conversion of the income statements of the Group’s subsidiaries from functional currency to the presentation
currency US Dollar for the years ended at December 31, 2023 and 2022.
Shift of currency exchange rates
USD Thousands
Average rate
2023
USD weakening
10%
USD strengthening
10%
Gross profit in the financial statements 250,514 250,514
EUR/USD 0.9246 0.8405 1.0170
CAD/USD 1.3496 1.2269 1.4846
Total effect on gross profit (20,700) 20,700
Shift of currency exchange rates
USD Thousands
Average rate
2022
USD weakening
10%
USD strengthening
10%
Gross profit in the financial statements 516,709 516,709
EUR/USD 0.9489 0.8626 1.0437
CAD/USD 1.3015 1.1832 1.4317
Total effect on gross profit (41,704) 41,704
d) Commodity price risk
The Group is subject to price risk associated with fluctuations in the market prices for oil and gas. Prices of oil and gas are affected by
the normal economic drivers of supply and demand as well as the financial investors and market uncertainty. Factors that influence
these include operational decisions, natural disasters, economic conditions, political instability or conflicts or actions by major oil
exporting countries. Price fluctuations can affect the Corporation’s financial position.
Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in the price of oil and natural gas.
Commodity prices are impacted by world economic events that affect supply and demand, which are generally beyond the Group’s
control. Changes in crude oil prices may significantly affect the Corporation’s results of operations, cash generated from operating
activities, capital spending and the Corporation’s ability to meet its obligations. The majority of the Corporation’s production is sold
under short-term contracts; consequently the Group is at risk to near term price movements. The Corporation manages this risk by
constantly monitoring commodity prices and factoring them into operational decisions, such as contracting or expanding its capital
expenditures program.
The Corporation enters into certain risk management contracts in order to manage the exposure to market risks from fluctuations
in commodity prices. These risk management contracts are not used for trading or speculative purposes. The Corporation has
designated its risk management contracts as effective accounting hedges, and thus has applied hedge accounting. As a result, all
risk management contracts are recorded at fair value at each reporting period with the change in fair value being recognized on the
statement of comprehensive income.
===== SIDA 40 =====
40
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
The Group had oil price sale financial hedges outstanding as at December 31, 2023, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
January 1, 2024 – December 31, 2024 17,700 WTI/WCS Differential USD -15.03/bbl
January 1, 2024 – December 31, 2024 6,250 WTI Sale Swap USD 80.94/bbl
The Group had condensate financial hedges outstanding as at December 31, 2023, which are summarized as follows:
Period Volume (barrels per day) Type Average Pricing
January 1, 2024 – March 31, 2024 3,000 C5/WTI Differential USD -1.60/bbl
The Group had no gas price sale financial hedges outstanding as at December 31, 2023.
The Group had electricity financial hedges outstanding as at December 31, 2023, which are summarized as follows:
Period Volume (MW) Type Average Pricing
October 1, 2025 – September 30, 2040 3 AESO CAD 75.00/MWh
All of the above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
The outstanding derivative instruments can be specified as follows:
Fair value of outstanding derivative instruments in the balance sheet:
USD Thousands
December 31, 2023 December 31, 2022
Assets Liabilities Assets Liabilities
Oil price hedge 28,291 – 1,155
Gas price hedge – – 7,771 –
Electricity price hedge – 202 – –
Total 28,291 202 7,771 1,155
Non-current – 202 – –
Current 28,291 – 7,771 1,155
Total 28,291 202 7,771 1,155
In addition to the outstanding derivative instruments in the balance sheet disclosed above, a gain of USD 18,928 thousand (2022:
USD 19,125 thousand) was recognised in the statement of operations in relation to settled oil and gas derivatives.
The table below summarizes the effect that a change in the oil and gas price would have had on the net result and equity at
December 31, 2023 and 2022:
2023 net result (USD Thousands) 172,979 172,979
Possible shift (%) (10%) 10%
Total effect on net result (USD Thousands) (60,010) 60,010
2022 net result (USD Thousands) 337,725 337,725
Possible shift (%) (10%) 10%
Total effect on net result (USD Thousands) (91,032) 91,032
===== SIDA 41 =====
41
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
e) Interest rate risk
The Group’s exposure to interest rate risk arises from the interest rate impact on its debt facilities. As at December 31, 2023, the
Group’s long-term debt is mainly comprised of a fixed coupon rate of 7.25%. As such, changes in interest rate will not have a
significant adverse impact on interest expense.
25. MANAGEMENT OF CAPITAL RISK
The objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its committed
work program requirements in order to create shareholder value. The Corporation may put in place new credit facilities, repay debt, or
other such restructuring activities as appropriate. Management continuously monitors and manages the capital and liquidity position in
order to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility.
No significant changes were made in the objectives, policies or procedures during the year ended December 31, 2023 or in the
comparative periods.
Through the ongoing management of its capital, the Corporation will modify the structure of its capital based on changing economic
conditions in the jurisdictions in which it operates. In doing so, the Corporation may issue new shares or debt, buy back issued
shares, or pay off any outstanding debt.
26. SALARY AND OTHER COMPENSATION EXPENSES
a) Employee compensation expenses
The following table provides a breakdown of gross salaries, short-term benefits, share-based compensation and other compensation
expenses included in the consolidated statement of comprehensive income:
USD Thousands 2023 2022
Salaries, bonuses and other short-term benefits 57,280 45,073
Security social costs 7,100 7,040
Share-based incentive plans1 11,690 7,997
76,070 60,110
1 Vested during the period and based on IFRS 2 valuation (see Note 18)
The overall increase in 2023 is mainly due to the increase in workforce in Canada following the Cor4 acquisition.
b) Remuneration of Directors and Senior Management
Remuneration of Directors and Senior Management includes all amounts earned and awarded to the Group’s Board of Directors and
Senior Management. Senior Management includes the Group’s President and Chief Executive Officer, Chief Financial Officer, General
Counsel and Corporate Secretary, Chief Operating Officer, Senior Vice President Canada, Vice President of Asset Management and
Corporate Planning Canada and Vice President of Corporate Planning and Investor Relations.
Directors’ fees include Board and Committee fees. Senior Management’s remuneration includes salary, short-term benefits, bonuses
and any other compensation earned is as follows:
USD Thousands 2023 2022
Directors’ fees 665 597
Senior Management’s salaries, bonuses and other short-term benefits 8,198 7,210
Share-based incentive plans paid to Senior Management 7,933 6,207
16,796 14,014
===== SIDA 42 =====
42
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022, AUDITED
27. 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 December 31, 2023:
CAD Millions 2024 2025 2026 2027 2028 Thereafter
Transportation service 1 27.9 29.2 38.4 43.4 46.4 555.6
Power2 9.8 9.8 9.8 9.8 9.8 –
Total commitments 37.7 39.0 48.2 53.2 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 January 1, 2024 - December 31,
2028.
28. RELATED PARTIES
During the year 2023, the Group paid USD 365 thousand to the Lundin Foundation in respect of sustainability advisory services
provided to the Group and USD 685 thousand to Orrön Energy in respect of office space rental for 2023.
During the year 2023, Orrön Energy paid USD 657 thousand to the Group in respect of support services provided to Orrön Energy
during 2023.
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.
29. SUBSEQUENT EVENTS
No other events have occurred since December 31, 2023, that are expected to have a substantial effect on this report.
===== SIDA 43 =====
Corporate Office
International Petroleum Corp
Suite 2000
885 West Georgia Street
Vancouver, BC
V6C 3E8, Canada
Tel: +1 604 689 7842
E-mail: info@international-petroleum.com
Web: international-petroleum.com□
===== SIDA 44 =====
Q4
International Petroleum Corporation
Management’s Discussion
and Analysis
For the three months ended and year ended
December 31, 2023
===== SIDA 45 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Contents
Non-IFRS Measures
References are made in this MD&A to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA),
“operating costs” and “net debt”/”net cash” which are not generally accepted accounting measures under 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 24.
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 37.
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 6
• Business Overview 6
• Operations Overview 10
FINANCIAL REVIEW 13
• Financial Results 13
• Capital Expenditure 22
• Financial Position and Liquidity 23
• Non-IFRS Measures 24
• Off-Balance Sheet Arrangements 26
• Outstanding Share Data 26
• Contractual Obligations and Commitments 26
• Critical Accounting Policies and Estimates 27
• Transactions with Related Parties 27
• Financial Risk Management 27
RISK FACTORS 28
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING 36
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 37
RESERVES AND RESOURCES ADVISORY 38
OTHER SUPPLEMENTARY INFORMATION 41
2
===== SIDA 46 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
INTRODUCTION
This management’s discussion and analysis (“MD&A”) for International Petroleum Corporation (“IPC” or the “Corporation” and,
together with its subsidiaries, the “Group”) is dated February 6, 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 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 2000, 885 West Georgia Street, Vancouver, BC V6C 3E8, Canada.
Basis of Preparation
The MD&A and the Financial Statements have been prepared in accordance with 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:
December 31, 2023 December 31, 2022
Average Period end Average Year end
1 EUR equals USD 1.0816 1.1050 1.0539 1.0666
1 USD equals CAD 1.3496 1.3251 1.3015 1.3538
1 USD equals MYR 4.5598 4.5950 4.3995 4.4050
IPC completed the acquisition of Cor4 Oil Corp. (“Cor4”) on March 3, 2023. In accordance with IFRS, the Financial Statements
have been prepared on that basis, with revenues and expenses related to the assets acquired in the Cor4 acquisition included in
the Financial Statements from March 3, 2023. Certain historical and forecast 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 ”Cor4 Acquisition”, “Operations
Overview – Production” and “Non-IFRS Measures” below.
3
===== SIDA 47 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
HIGHLIGHTS
2023 Business Highlights
• Average net production of approximately 49,600 boepd for the fourth quarter of 2023 was in line with the high end of the
guidance range for the period (52% heavy crude oil, 13% light and medium crude oil and 35% natural gas).(1)
• Full year 2023 average net production was 51,100 boepd, above the high end of annual guidance and a record high for IPC.(1)
• Following the decision in Q1 2023 to develop Phase 1 of the Blackrod project, work on the project has progressed in line
within the overall schedule and budget to first oil in late 2026. Key events include signing of the engineering, procurement
and fabrication contract with the Engineering Procurement and Construction (EPC) contractor for the Central Processing
Facility and advancement of facility engineering and fabrication works, access road expansion and site civil preparation works,
and drilling operations.
• Successfully integrated the Suffield area assets acquired from Cor4 Oil Corp. (Cor4) in March 2023 and executed the drilling
program in the Ellerslie play with eight wells drilled in 2023.
• Production sustaining Pad L at Onion Lake Thermal (OLT) successfully brought online, supporting record average daily
production in 2023 from the OLT asset.
• Sale of small non-core assets in Canada for MUSD 20, at a significant premium to 2P reserves net present value.(2)
• In Malaysia, successfully completed planned maintenance turnaround at the Bertam field on scope, schedule, and budget.
• In France, successfully delivered three new production wells at Villeperdue West and one side-track well at Merisier.
• 9.3 million common shares purchased and cancelled from December 5, 2022 to December 4, 2023 under IPC’s 2022/2023
NCIB and a further 1.8 million common shares purchased for cancellation during December 2023 and January 2024 under the
renewed 2023/2024 NCIB. 7% of IPC’s common shares outstanding were reduced through the NCIB in 2023.
• In Q3 2023, published IPC’s fourth annual Sustainability Report and its first stand-alone report aligned with the Task Force on
Climate-Related Financial Disclosures (TCFD).
• Commitment to reduce IPC’s net emissions intensity to 20 kg CO2/boe by 2025, is extended to remain at that level through
end 2028.
2023 Financial Highlights
• Operating costs per boe of USD 18.3 for the fourth quarter of 2023 and USD 17.6 for the full year in line with full year
guidance of USD 17.5 to 18 per boe.(3)
• Strong operating cash flow (OCF) generation for the fourth quarter and full year 2023 amounted to MUSD 74 and MUSD
353, respectively.(3)
• Capital and decommissioning expenditures of MUSD 130 for the fourth quarter and MUSD 327 for the full year 2023, in line
with most recent full year guidance of MUSD 330.
• Positive free cash flow (FCF) generation for the full year 2023 of MUSD 3, with negative FCF generation of MUSD 65 for the
fourth quarter in line with expectations and taking into account the significant capital expenditures during the quarter. FCF
before 2023 Blackrod capital expenditure of MUSD 240, was MUSD 243. (3)
• Net cash of MUSD 58 and gross cash of MUSD 517 as at December 31, 2023. (3)
• Net result of MUSD 30 for the fourth quarter of 2023 and MUSD 173 for the full year 2023.
• Further strengthened IPC’s financial position with an increase of IPC’s bonds to MUSD 450 due February 2027 and an
increase of IPC’s undrawn Canadian revolving credit facility to MCAD 180.
Reserves and Resources
• Total 2P reserves as at December 31, 2023 of 468 MMboe, representing a reserves replacement ratio of 78% compared to
year-end 2022, 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)
• 2P reserves net asset value (NAV) as at December 31, 2023 of MUSD 3,087 (10% discount rate). (1)(2)(4)(5)
2024 Annual Guidance
• Full year 2024 average net production forecast at 46,000 to 48,000 boepd. (1)
• Full year 2024 operating costs guidance forecast at USD 18 to 19 per boe.(3)
• Full year 2024 OCF guidance estimated at between MUSD 261 to 382 (assuming Brent USD 70 to 90 per boe). (3)
• Full year 2024 capital and decommissioning expenditures guidance forecast at MUSD 437, including MUSD 362 relating to
continued development of Phase 1 of the Blackrod project.
• Full year 2024 FCF ranges from approximately MUSD 144 to 268 (assuming Brent USD 70 to 90 per boe) before taking into
account proposed Blackrod capital expenditures, or MUSD -218 to -94 including proposed Blackrod capital expenditures. (3)
4
===== SIDA 48 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Business Plan Production and Cash Flow Guidance
• 2024 – 2028 business plan forecasts:
• average net production forecast approximately 55,000 boepd. (1)
• capital expenditure forecast of USD 11 per boe, including USD 6 per boe for the Blackrod Phase 1 project.
• operating costs forecast of USD 18 per boe.(3)
• FCF forecast of approximately MUSD 900 to 1,800 (assuming Brent USD 75 to 95 per boe). (3)(7)
• 2029 – 2033 business plan forecasts:
• average net production forecast of approximately 65,000 boepd. (1)
• capital expenditure forecast of USD 5 per boe.
• operating costs forecast of USD 18 per boe.(3)
• FCF forecast of approximately MUSD 1,750 to 2,800 (assuming Brent 75 to 95 USD per boe). (3)(7)
Three months ended
December 31
Year ended
December 31
USD Thousands 2023 2022 2023 2022
Revenue 198,460 254,615 853,906 1,129,298
Gross profit 39,955 95,411 250,514 516,709
Net result 29,710 61,183 172,979 337,725
Operating cash flow(3) 73,634 113,668 353,048 622,947
Free cash flow(3) (64,688) 65,288 2,689 430,242
EBITDA(3) 66,284 125,651 350,618 639,480
Net Cash(3) 58,043 175,098 58,043 175,098
5
===== SIDA 49 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
OPERATIONS REVIEW
Business Overview
IPC’s strategy since launching IPC in April 2017 remains unchanged: to deliver operational excellence through responsible
operatorship, maintain financial resilience, maximise the value of our resource base, target growth organically and through
acquisitions, and deliver stakeholder returns.
IPC has followed through on this vision resulting in material value creation for all stakeholders through efficient capital allocation
and operational proficiency. Since inception, IPC has sustained no material safety incidents across all operating domains, delivered
within or ahead of guidance every reporting year, increased the Reserves Life Index (RLI) from 8 years to 27 years largely through
5 accretive acquisitions, and cancelled over 62.5 million common shares.
The company is strongly positioned to continue following through on our strategy supported by a strong balance sheet to start
2024 with net cash of USD 58 million and material production growth expected from the Blackrod Phase 1 development with first
oil expected in late 2026.(3)
Following a year of exceptionally high oil and gas prices in 2022 with Brent prices averaging over USD 100 per barrel for the full
year 2022, IPC continued to benefit in 2023 from strong oil benchmark prices, with average Brent prices over USD 82 per barrel
for the full year. Quarterly average Brent prices during 2023 ranged between USD 78 to USD 87 per barrel. Strong oil and gas
demand is expected to continue in 2024 which, along with such factors as OPEC+ decisions to curtail supply, potential market
and transportation disruptions due to ongoing geopolitical tensions and current global observed crude inventory levels are at
the bottom end of the five-year average could limit downside risks on commodity prices in 2024. These positive factors may be
partially offset by increased forecast supply from countries such as the United States in a Presidential election year, which could
be expected to limit price upside.
In Canada, fourth quarter 2023 West Texas Intermediate (WTI) to Western Canadian Select (WCS) crude price differentials
averaged around USD 22 per barrel, with average differentials of around USD 18.5 for the full year. The Trans-Mountain (TMX)
pipeline is currently expected to commence line-fill in the first half of 2024 which should benefit the WTI/WCS differentials during
2024 and into the future. IPC has hedged the WTI/WCS differential for approximately 70% of our Canadian crude production at
USD 15 per barrel and hedged 25% of our WTI exposure for approximately USD 81 per barrel for 2024.
Gas markets in 2023 witnessed a substantial decrease from the 2022 average AECO benchmark prices above CAD 5 per Mcf. The
average AECO gas price was CAD 2.30 per Mcf for the fourth quarter of 2023, and an average of CAD 2.60 for the full year 2023.
IPC’s realized prices for gas were CAD 2.55 per Mcf for the fourth quarter of 2023 and CAD 3.36 per Mcf for the full year 2023
taking into account hedges in place until October 31, 2023.
IPC benefits from a well-balanced mix of production comprising approximately 54% Canadian Crude, 33% Canadian Natural
Gas and 13% Brent weighted oil, on average over 2023. With strong commodity pricing, combined with delivering operational
excellence above the high end of IPC’s 2023 guidance, IPC has again been able to deliver a very strong financial performance in
the fourth quarter and throughout the full year 2023.
Fourth Quarter and Full Year 2023 Highlights
During the fourth quarter of 2023, IPC’s assets delivered average net production of 49,600 boepd, in line with high-end guidance
for the quarter. This was made possible by high operational performance across all of IPC’s assets as well as the production
contribution from IPC’s 2023 investment program in Canada and France, notwithstanding some downtime from two production
wells in Malaysia through Q4 which have now been worked over and are back on stream as of end January 2024. Full year 2023
average net production of 51,100 boepd was a record high for IPC and on target with guidance of greater than 50,000 boepd.(1)
IPC’s operating costs per boe for the fourth quarter of 2023 was USD 18.3. Full year 2023 operating costs per boe was USD 17.6,
in line with guidance of USD 17.5 to 18 per boe.(3)
Operating cash flow (OCF) generation for the fourth quarter of 2023 was USD 74 million. Full year 2023 OCF was USD 353 million
in line with the most recent guidance of USD 340 to 365 million.(3)
Capital and decommissioning expenditure for the fourth quarter of 2023 was USD 130 million. Full year 2023 capital and
decommissioning expenditure of USD 327 million was in line with guidance of USD 330 million.
Free cash flow (FCF) generation was in line with guidance at negative USD 65 million during the fourth quarter of 2023, reflecting
the higher level of capital expenditure on the Blackrod Phase 1 development project. Full year 2023 FCF generation was USD 3
million, at the higher end of the most recent guidance of USD -65 to 5 million.(3)
As at December 31, 2023, IPC’s net cash position was USD 58 million. IPC’s gross cash on the balance sheet amounts to USD 517
million which provides IPC with significant financial strength to continue progressing its strategies in 2024, including advancing the
Phase 1 Blackrod development, returning value to shareholders through the 2023/2024 NCIB, and remaining opportunistic to M&A.(3)
6
===== SIDA 50 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Blackrod Project
In Q1 2023, IPC announced the decision to advance the development of Phase 1 of the Blackrod project. Development capital
expenditure to first oil is estimated at USD 850 million nominal. First oil of the Phase 1 development is estimated to be in late
2026, with forecast net production of 30,000 bopd by 2028. The Blackrod Phase 1 development targets 218 million barrels of 2P
reserves and the sanction case WTI breakeven estimated as of January 1, 2023, using the December 31, 2022 price forecasts
of IPC’s qualified independent reserves evaluator, Sproule Associates Limited (Sproule), was USD 59 per barrel assuming a 10%
discount rate. Following capital expenditure of USD 240 million invested in 2023, the project is forecast to add USD 981 million
to IPC’s 2P reserves net present value (NPV) as at January 1, 2024, with a WTI breakeven of USD 54.5 per barrel assuming a
10% discount rate, using Sproule’s December 31, 2023 price forecasts. IPC forecasts capital expenditure in 2024 for the Blackrod
project of USD 362 million, with the remainder of the estimated total project budget to be invested prior to first oil. With greater
than 1 billion barrels of contingent resources (best estimate, unrisked) remaining, Blackrod presents material upside to future
phase expansions beyond the initial first Phase of development.(1)(2)(4)
Project activities for the multi-year Phase 1 development have progressed in line with schedule and budget. Following the
successful completion of Front-End Engineering and Design (FEED) studies through 2022, IPC formerly established a partnership
with the Engineering, Procurement and Construction (EPC) contractor in 2023 through contractual commitments for the Central
Processing Facility (CPF). As at the end of 2023, major long lead items have been procured, fabrication has commenced, site civil
and commercial road expansion works have advanced, drilling is underway, and third-party pipeline commercial agreements are
progressing according to plan.
Following significant project milestones achieved through 2023, IPC is well positioned to continue advancing responsible
development of the Blackrod Phase 1 development through 2024. With a combination of contractual commitments and financial
foreign exchange hedges locked in at more favourable rates than assumed at project sanction, IPC sits comfortably within the
overall budget and schedule guidance to first oil. IPC intends to fund the remaining Phase 1 development costs with forecast cash
flow generated by its operations and cash on hand.(3)
M&A
IPC was pleased to close the strategic acquisition of Cor4 in March 2023 for a consideration of USD 62 million. The acquisition,
located in the Suffield area, brought in 15.9 MMboe of 2P reserves as at January 1, 2023 and delivered greater than 5,000 boepd
through 2023. The asset holds high quality mineral rights within the Ellerslie formation, an attractive feature that crystallised
through 2023 as eight wells were successfully drilled into this play supporting higher than forecast production rates. The acquired
asset team has been effectively integrated within IPC and further synergies within Suffield area are of continued focus as we seek
to unlock further value potential.(1)(2)
Following the strategic divestiture of small non-core production and land assets in the greater John Lake area in Canada announced
in Q3 2023, IPC further sold non-producing lands in Q4 for a consideration of USD 3.5 million. The total proceeds in aggregate from
the non-core dispositions in Q3 and Q4 was in excess of USD 20 million. The 2P reserves and NPV10 as of January 1, 2023 were
0.6 MMboe and USD 7.7 million respectively for the divested properties.(2)(4)
IPC continues to review potential M&A opportunities. IPC has added over USD 2.5 billion of aggregate value in FCF generation and
2P reserves NPV increases, from IPC’s last 5 acquisitions.(3)(4)
Stakeholder Returns: Normal Course Issuer Bid
During the period of December 5, 2022 to December 4, 2023, IPC purchased and cancelled an aggregate of approximately 9.3
million common shares under the 2022/2023 normal course issuer bid / share repurchase program (NCIB). The average price of
shares purchased under the 2022/2023 NCIB was SEK 102 / CAD 13.0 per share.
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. By the end of January 2024, IPC repurchased for cancellation over
600,000 common shares under the 2023/2024 NCIB. The average price of common shares purchased under the 2023/2024 NCIB
during December 2023 and January 2024 was SEK 114.5 / CAD 15 per share.
As at February 6, 2023, IPC had a total of 126,479,966 common shares issued and outstanding, of which IPC holds 102,200
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 of 6.5 million common shares by December 4, 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
Blackrod will prove to be a winning formula for our stakeholders.
7
===== SIDA 51 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Environmental, Social and Governance (ESG) Performance
Responsible operatorship and ensuring that IPC adheres to the highest principles of business conduct have been integral parts of
how IPC does business since it started in 2017.
With the publication of IPC’s second quarter 2023 financial report, IPC was very pleased to publish its fourth Sustainability Report
and its first stand-alone report aligned with the Task Force on Climate-Related Financial Disclosures. IPC is committed to the
continued advancement of ESG practices in its sustainability focus areas. The Group’s six sustainability priorities are:
• Ethics & Integrity
• Rewarding Workplace
• Health & Safety
• Community Engagement
• Climate Action
• Environmental Stewardship
As part of IPC’s commitment to operational excellence, its objective is to reduce risk and eliminate hazards to prevent the
occurrence of accidents, ill health, and environmental damage, as these are essential to the success of IPC’s operations. During
the fourth quarter and for the full year 2023, IPC recorded no material safety or environmental incidents.
With respect to climate action, as previously announced, IPC targets a reduction of net GHG emissions intensity by the end of
2025 to 50% of IPC’s 2019 baseline and IPC remains on track to achieve this reduction. IPC has extended its commitment to
remain at 2025 levels of 20 kg CO2/boe through to the end of 2028.
Reserves, Resources and Value
As at the end of December 2023, IPC’s 2P reserves are 468 MMboe. During 2023, IPC replaced 78% of the annual 2023
production. The reserves life index (RLI) as at December 31, 2023, remains at approximately 27 years.(1)(2)
The net present value (NPV) of IPC’s 2P reserves as at December 31, 2023 was USD 3,023 million. IPC’s net asset value (NAV)
was USD 3,081 or SEK 244 / CAD 32 per share as at December 31, 2023.(1)(2)(4)(5)(6)
In addition, IPC’s best estimate contingent resources (unrisked) as at December 31, 2023 are 1,145 MMboe, ofwhich 1,066
MMboe relate to future potential phases of the Blackrod project.(1)(2)
2024 Budget and Operational Guidance
IPC is pleased to announce its 2024 average net production guidance is 46,000 to 48,000 boepd. IPC forecasts operating costs for
2024 to be USD 18 to 19 per boe.(1)(3)
IPC forecasts FCF generation based on its 2P reserves base of in aggregate of more than USD 900 to 1,800 million over the period
of 2024 to 2028. In addition, IPC forecasts FCF generation of USD 1,750 to 2,800 million over the period of 2029 to 2033.(2)(3)(7)
IPC’s 2024 capital and decommissioning expenditure budget is USD 437 million, with USD 362 million forecast relating to the
Phase 1 development of the Blackrod project. The remainder of the 2024 budget in Canada includes drilling at the Suffield and
Ferguson assets, further development of the Mooney asset, and ongoing optimization work. IPC also completed well workover
operations in Malaysia by January 2024 and expects to conduct technical studies for future development potential. Following the
successful execution of the 2023 drilling campaign in France, the subsurface teams are maturing drilling targets within the Paris
Basin.
2024 is set to be a record growth investment year for IPC, we have therefore set a limited sustaining capital expenditure plan of
USD 75 million, inclusive of decommissioning, across the producing assets in the portfolio. With robust cashflow being generated
from the producing assets and gross cash resources of USD 517 million, IPC intends to fully complete the remaining share
buybacks available under the NCIB program through 2024.
In all of IPC’s areas of operation, IPC has significant flexibility to control its pace of spend based on the development of commodity
prices during 2024.
Further details regarding IPC’s proposed 2024 budget and operational guidance will be provided at IPC’s Capital Markets Day
presentation to be held on February 6, 2024 at 14:00 GMT. A copy of the Capital Markets Day presentation will be available on
IPC’s website at www.international-petroleum.com.
8
===== SIDA 52 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Notes:
(1) See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory” below. See also the
material change report (MCR) available on IPC’s website at www.international-petroleum.com and filed on the date of
this press release under IPC’s profile on SEDAR+ at www.sedarplus.ca. IPC completed the acquisition of Cor4 Oil Corp.
(Cor4) on March 3, 2023. The Financial Statements 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
historical 2023 operational and financial information included in the MD&A, including production, operating costs, OCF , FCF
and EBITDA related to the assets acquired in the Cor4 acquisition, are reported based on the effective date of the Cor4
acquisition of January 1, 2023.
(2) See “Reserves and Resources Advisory“ below. Further information with respect to IPC’s reserves, contingent resources
and estimates of future net revenue, including assumptions relating to the calculation of NPV, are described in the MCR.
Reserves replacement ratio is based on 2P reserves of 471.5 MMboe as at December 31, 2022 (not including 2P reserves
related to the Brooks assets acquired in the Cor4 acquisition), sales production during 2023 of 17.7 MMboe, net additions
to 2P reserves during 2023 of 16.0 MMboe, other revisions downward of 2.2 MMboe, and 2P reserves of 468 MMboe as
at December 31, 2023.
(3) Non-IFRS measure, see “Non-IFRS Measures” below and in the MD&A.
(4) NPV is after tax, discounted at 10% and based upon the forecast prices and other assumptions further described in the
MCR. See “Reserves and Resources Advisory” below.
(5) NAV is calculated as NPV plus net cash of USD 58 million as at December 31, 2023.
(6) NAV per share is based on 126,992,066 IPC common shares outstanding as at December 31, 2023. NAV per share is not
predictive and may not be reflective of current or future market prices for IPC common shares.
(7) 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 MCR. IPC’s market capitalization is at close on
January 19, 2024 (USD 1,378 million based on 113.6 SEK/share, 126.99 million IPC shares outstanding and exchange rate
of 10.47 SEK/USD). IPC’s current business plans and assumptions, and the business environment, are subject to change.
Actual results may differ materially from forward-looking estimates and forecasts. See “Forward-Looking Statements”
below.
9
===== SIDA 53 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Operations Overview
2023 Overview
In 2023, IPC successfully demonstrated its commitment to operational excellence, with record annual net average production and
no material safety incidents or harm to the environment.
In Canada, the Blackrod Phase 1 development has progressed in accordance with plan. Initial construction camps have been
installed and site preparations have been executed to allow for critical facility and drilling equipment delivery in Q1 2024.
The major EPC contract has been signed for the central processing facility, bringing a higher degree of certainty for a significant
portion of the Phase 1 capital expenditure to first oil. Drilling operations commenced in Q4 2023, with the first utility wells
successfully executed in line with expectations. At Onion Lake Thermal, daily production is touching facility nameplate capacity of
14,000 boepd with the new production sustaining Pad L brought online ahead of schedule in Q3 2023. At Suffield, all eight planned
new production wells in the exciting Ellerslie play have been brought online and are producing ahead of expectations. In France,
all three of the budgeted Villeperdue West oil wells and the Merisier side-track oil well have been successfully brought online with
production performing ahead of forecast. At Bertam in Malaysia, the two planned production well workovers have progressed in
line with plan with the first well now back online and the second well expected to follow early in Q1 2024.
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.
Production
Average daily net production for the fourth quarter 2023 was in line with IPC’s high end guidance at 49,600 boepd. The quarter
marks the end of a record production year for IPC with exceptional operational performance and the production benefit from the
very successful 2023 development investment program. In Canada, strong operational performance has been supplemented
by the newly drilled Suffield area Ellerslie production wells and ahead of expectations initial results from the new production
sustaining Pad L at Onion Lake Thermal. In addition, IPC continues to see the benefit of 2023 development campaign in France
with the three new wells at Villeperdue and the side-track well at Merisier producing above forecast.
With exceptional operational delivery through 2023, IPC exits the year with a record net average production of 51,100 boepd,
1,100 boepd above the original 2023 Capital Markets Day (CMD) high end guidance of 50,000 boepd.
The production during Q4 2023 with comparatives is summarized below:
Production
in Mboepd
Three months ended
December 31
Year ended
December 31
2023 2022 2023 2022
Crude oil
Canada – Northern Assets 15.5 16.0 15.5 15.6
Canada – Southern Assets1 11.4 9.0 11.8 8.7
Malaysia 2.5 5.2 3.8 5.3
France 2.8 2.7 2.8 2.7
Total crude oil production 32.2 32.9 33.9 32.3
Gas
Canada – Northern Assets 0.4 0.1 0.4 0.1
Canada – Southern Assets 17.0 16.2 16.8 16.2
Total gas production 17.4 16.3 17.2 16.3
Total production 49.6 49.2 51.1 48.6
Quantity in MMboe 4.56 4.53 18.65 17.74
1 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”.
10
===== SIDA 54 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
CANADA
Production
in Mboepd WI
Three months ended
December 31
Year ended
December 31
2023 2022 2023 2022
- Oil Onion Lake Thermal 100% 13.6 13.1 13.3 12.7
- Oil Suffield Area1 100% 10.1 6.7 10.2 7.1
- Oil Ferguson 100% 1.3 2.3 1.5 1.6
- Oil Other 50-100% 1.9 2.9 2.3 2.9
- Gas1 ~100%2 17.4 16.3 17.2 16.3
Canada 44.3 41.3 44.5 40.6
1 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.
2 On a well count basis
Production
Net production from IPC’s Canadian assets during Q4 2023 was ahead of the high-end guidance at 44,300 boepd with continued
strong operational performance at all the major producing assets. At Onion Lake Thermal, daily production has been stable close
to the facility nameplate capacity of 14,000 boepd with four well pairs from production sustaining Pad L online ahead of schedule.
The Suffield area oil and gas producing assets continue to deliver above forecast, where base well rate optimization has been
supplemented by ahead of expectations production performance from the newly drilled Ellerslie play oil wells.
Organic Growth and Capital Projects
In Canada, the Blackrod Phase 1 development was sanctioned in Q1 2023. A reduced base business budget for the remainder of
the assets in Canada was set for 2023 with a focus on oil well drilling in the Suffield Ellerslie formation and the completion of the
next production sustaining Pad L at Onion Lake Thermal.
During the fourth quarter, the Blackrod Phase 1 development progressed in accordance with plan. Site civil preparations and road
expansion work have been completed in preparation for the key facility and drilling equipment delivery in Q1 2024. Drilling activity
commenced on schedule in Q4 2023 and is progressing in line with expectations.
As of the end of Q4 2023 in the Suffield area, the six originally planned Ellerslie play wells, as well as the two additional wells
announced in Q3 2023, have been drilled, brought online and are performing ahead of expectations.
At Onion Lake Thermal, daily production is stable close to the facility nameplate capacity of 14,000 boepd with four well pairs from
production sustaining Pad L online.
MALAYSIA
Production
in Mboepd WI
Three months ended
December 31
Year ended
December 31
2023 2022 2023 2022
Bertam 100% 2.5 5.2 3.8 5.3
Production
Net production at Bertam in Malaysia in Q4 2023 was below guidance at 2.5 boepd, with two production wells offline awaiting
workover intervention in the quarter. The two workovers were completed and both wells were back on-stream as of end January
2024.
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 in the north east of the
field.
11
===== SIDA 55 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
FRANCE
Production
in Mboepd WI
Three months ended
December 31
Year ended
December 31
2023 2022 2023 2022
France
- Paris Basin 100%1 2.5 2.3 2.4 2.4
- Aquitaine 50% 0.3 0.4 0.4 0.3
2.8 2.7 2.8 2.7
1 Except for the working interest in the Dommartin Lettree field of 43%
Production
Net production in France during Q4 2023 was in line with the guidance at 2,800 boepd.
Organic Growth
In France, all three Villeperdue West oil wells and the Merisier side-track oil well have been drilled, completed and brought online
with production performing ahead of forecast.
IPC continues to mature future development projects in France, with focus towards the undeveloped resource base within the
Paris Basin supported by the positive results following the 2023 development campaign.
12
===== SIDA 56 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
FINANCIAL REVIEW
Financial Results
Selected Annual Financial Information
Selected consolidated statement of operations is as follows:
USD Thousands 2023 2022 2021
Revenue 853,906 1,129,298 666,409
Gross profit 250,514 516,709 210,321
Net result 172,979 337,725 146,059
Earnings per share – USD 1.31 2.30 0.94
Earnings per share fully diluted – USD 1.28 2.25 0.92
Operating cash flow1 353,048 622,947 336,732
Free cash flow1 2,689 430,242 262,884
EBITDA1 350,618 639,480 330,754
Net cash / (debt) at period end1 58,043 175,098 (94,312)
1 See definition on page 24 under “Non-IFRS measures”
Summarized consolidated balance sheet information is as follows:
USD Thousands December 31, 2023 December 31, 2022 December 31, 2021
Non-current assets 1,372,388 1,041,051 1,122,514
Current assets 690,597 638,566 151,160
Total assets 2,062,985 1,679,617 1,273,674
Total non-current liabilities 779,838 564,381 331,152
Current liabilities 202,888 149,905 94,979
Total liabilities 982,726 714,286 426,131
Net assets 1,080,259 965,331 847,543
Working capital (including cash) 487,709 488,661 56,181
13
===== SIDA 57 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Selected Interim Financial Information
Selected interim condensed consolidated statement of operations is as follows:
USD Thousands 2023 Q4-23 Q3-23 Q2-23 Q1-23 2022 Q4-22 Q3-22 Q2-22 Q1-22
Revenue 853,906 198,460 257,366 205,564 192,516 1,129,298 254,615 299,361 315,540 259,782
Gross profit 250,514 39,955 93,429 52,747 64,383 516,709 95,411 140,489 161,709 119,100
Net result 172,979 29,710 71,681 32,025 39,563 337,725 61,183 90,503 105,217 80,822
Earnings per share –
USD 1.31 0.23 0.56 0.24 0.29 2.30 0.45 0.63 0.70 0.52
Earnings per share fully
diluted – USD 1.28 0.22 0.54 0.24 0.28 2.25 0.44 0.62 0.68 0.51
Operating cash flow1 353,048 73,634 119,142 84,372 75,900 622,947 113,668 171,654 192,515 145,110
Free cash flow1 2,689 (64,688) 34,703 16,415 16,259 430,242 65,288 116,681 151,792 96,479
EBITDA1 350,618 66,284 123,054 85,201 76,079 639,480 125,651 174,328 194,038 145,463
Net cash / (debt) at
period end1 58,043 58,043 83,097 63,548 66,956 175,098 175,098 88,615 14,382 (42,367)
1 See definition on page 24 under “Non-IFRS measures”
Selected Interim Financial Information
The Group operates within several geographical areas. Operating segments are reported at a country level, with Canada being
further analyzed by main areas: (i) Canada – Northern Assets (comprising mainly of the Onion Lake Thermal asset) and (ii) Canada –
Southern Assets (comprising of the Suffield assets (including the Brooks assets acquired as part of the Cor4 acquisition) and the
Ferguson asset). This is consistent with the internal reporting provided to IPC management. The following tables present certain
segment information.
Three months ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 105,268 62,240 15,313 28,617 – 211,438
NGLs – 327 – – – 327
Gas 118 14,656 – – – 14,774
Net sales of oil and gas 105,386 77,223 15,313 28,617 – 226,539
Change in under/over lift
position – – – (8,442) – (8,442)
Royalties (14,657) (10,807) – (1,545) – (27,009)
Hedging settlement 3,205 3,754 – – – 6,959
Other operating revenue – – – 228 185 413
Revenue 93,934 70,170 15,313 18,858 185 198,460
Operating costs (23,868) (38,651) (9,170) (11,679) – (83,368)
Cost of blending (37,601) (6,872) – – – (44,473)
Change in inventory position (638) 873 1,217 (25) – 1,427
Depletion and decommissioning
costs (9,165) (14,654) (2,982) (3,633) – (30,434)
Depreciation of other tangible
fixed assets – – (1,309) – – (1,309)
Exploration and business
development costs – – – (30) (318) (348)
Gross profit/(loss) 22,662 10,866 3,069 3,491 (133) 39,955
14
===== SIDA 58 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Three months ended – December 31, 2022
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 101,127 52,721 44,361 29,095 – 227,304
NGLs – 142 – – – 142
Gas 256 35,656 – – – 35,912
Net sales of oil and gas 101,383 88,519 44,361 29,095 – 263,358
Change in under/over lift
position – – – (7,642) – (7,642)
Royalties (10,006) (8,989) – (1,864) – (20,859)
Hedging settlement 12,308 7,277 – – – 19,585
Other operating revenue – – – 173 – 173
Revenue 103,685 86,807 44,361 19,762 – 254,615
Operating costs (23,247) (32,964) (9,394) (8,900) – (74,505)
Cost of blending (39,494) (7,040) – – – (46,534)
Change in inventory position (551) 124 (4,111) (54) – (4,592)
Depletion and decommissioning
costs (8,256) (10,591) (8,667) (2,806) – (30,320)
Depreciation of other tangible
fixed assets – – (2,695) – – (2,695)
Exploration and business
development costs – – – – (558) (558)
Gross profit/(loss) 32,137 36,336 19,494 8,002 (558) 95,411
Year ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 430,231 258,660 101,237 81,093 – 871,221
NGLs – 1,172 – – – 1,172
Gas 373 66,965 – – – 67,338
Net sales of oil and gas 430,604 326,797 101,237 81,093 – 939,731
Change in under/over lift position – – – 400 – 400
Royalties (60,152) (41,025) – (5,120) – (106,297)
Hedging settlement 1,585 17,343 – – – 18,928
Other operating revenue – 7 – 867 270 1,144
Revenue 372,037 303,122 101,237 77,240 270 853,906
Operating costs (94,817) (155,178) (35,679) (36,288) – (321,962)
Cost of blending (146,204) (26,792) – – – (172,996)
Change in inventory position (448) 952 3,358 (207) – 3,655
Depletion and decommissioning
costs (24,969) (45,135) (17,800) (14,018) – (101,922)
Depreciation of other tangible
fixed assets – – (7,812) – – (7,812)
Exploration and business
development costs – (834) – (39) (1,482) (2,355)
Gross profit/(loss) 105,599 76,135 43,304 26,688 (1,212) 250,514
15
===== SIDA 59 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Year ended – December 31, 2022
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Other Total
Crude oil 513,349 265,016 184,143 112,379 – 1,074,887
NGLs – 774 – – – 774
Gas 1,082 153,672 – – – 154,754
Net sales of oil and gas 514,431 419,462 184,143 112,379 – 1,230,415
Change in under/over lift position – – – (8,553) – (8,553)
Royalties (59,353) (46,503) – (6,660) – (112,516)
Hedging settlement 18,842 283 – – – 19,125
Other operating revenue – 111 – 716 – 827
Revenue 473,920 373,353 184,143 97,882 – 1,129,298
Operating costs (101,443) (115,574) (35,051) (35,588) – (287,656)
Cost of blending (155,375) (33,797) – – – (189,172)
Change in inventory position 721 317 (1,916) 720 – (158)
Depletion and decommissioning
costs (33,097) (41,980) (34,687) (12,277) – (122,041)
Depreciation of other tangible
fixed assets – – (10,787) – – (10,787)
Exploration and business
development costs 97 – – – (2,872) (2,775)
Gross profit/(loss) 184,823 182,319 101,702 50,737 (2,872) 516,709
Three months and year ended December 31, 2023, Review
Revenue
Total revenue amounted to USD 198,460 thousand for Q4 2023, compared to USD 254,615 thousand for Q4 2022 and USD
853,906 thousand for the year ended December 31, 2023 compared to USD 1,129,298 thousand for the year ended December 31,
2022 and is analyzed as follows:
USD Thousands
Three months ended
December 31
Year ended
December 31
2023 2022 2023 2022
Crude oil sales 211,438 227,304 871,221 1,074,887
Gas and NGL sales 15,101 36,054 68,510 155,528
Change in under/overlift position (8,442) (7,642) 400 (8,553)
Royalties (27,009) (20,859) (106,297) (112,516)
Hedging settlement 6,959 19,585 18,928 19,125
Other operating revenue 413 173 1,144 827
Total revenue 198,460 254,615 853,906 1,129,298
The main components of total revenue for the three months and year ended December 31, 2023, and December 31, 2022,
respectively, are detailed below.
16
===== SIDA 60 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Crude oil sales
Three months ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 105,268 62,240 15,313 28,617 211,438
- Quantity sold in bbls 1,901,026 1,085,848 179,754 349,216 3,515,844
- Average price realized USD per bbl 55.37 57.32 85.19 81.95 60.14
Three months ended – December 31, 2022
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 101,127 52,721 44,361 29,095 227,304
- Quantity sold in bbls 1,824,392 900,832 473,071 330,014 3,528,309
- Average price realized USD per bbl 55.43 58.52 93.77 88.16 64.42
Crude oil revenue was 7% lower in Q4 2023 compared to Q4 2022 mainly due to lower oil prices. Canadian - Southern Assets
sales volumes are 21% higher in Q4 2023 compared to Q4 2022 as a result of the Cor4 acquisition in Q1 2023 and Malaysia
sales volume are 62% lower in Q4 2023 compared to Q4 2022 as a result of two production wells offline awaiting workover
intervention.
The Suffield area assets and Onion Lake crude oil in Canada are blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada. The Canadian realized sales price is based on the Western Canadian Select (“WCS”) price which trades at a discount to
West Texas Intermediate (“WTI”). For Q4 2023, WTI averaged USD 79 per bbl compared to USD 83 per bbl for Q4 2022 and the
average discount to WCS used in IPC’s pricing formula was USD 22 per bbl compared to USD 26 per bbl for Q4 2022.
The realized sales price for Malaysia and France is based on Dated Brent crude oil prices. There was one cargo lifting in Malaysia
during Q4 2023 and two cargo liftings in Q4 2022. Produced unsold oil barrels from Bertam at the end of Q4 2023 amounted to
163,000 barrels, see Change in Inventory Position section below. The average Dated Brent crude oil price was USD 84 per bbl for
Q4 2023 compared to USD 89 per bbl for the comparative period.
Year ended – December 31, 2023
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 430,231 258,660 101,237 81,093 871,221
- Quantity sold in bbls 7,426,431 4,334,552 1,112,408 989,802 13,863,193
- Average price realized USD per bbl 57.93 59.67 91.01 81.93 62.84
Year ended – December 31, 2022
USD Thousands Canada –
Northern Assets
Canada –
Southern Assets Malaysia France Total
Crude oil sales
- Revenue in USD thousands 513,349 265,016 184,143 112,379 1,074,887
- Quantity sold in bbls 6,880,263 3,492,721 1,646,301 1,143,130 13,162,415
- Average price realized USD per bbl 74.61 75.88 111.85 98.31 81.66
The Suffield area assets and Onion Lake crude oil in Canada are blended with purchased condensate diluent volumes
to meet pipeline specifications. As a result of the blended volumes, actual sales volumes are higher than produced volumes for
Canada.
17
===== SIDA 61 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Crude oil revenue was lower by 19% during the year ended December 31, 2023 compared to the year ended December 31, 2022
mainly due to lower oil prices despite higher sales volumes driven by the Cor4 acquisition and Onion Lake performance.
The Canadian realized sales price is based on the WCS price which trades at a discount to WTI. WTI averaged USD 78 per bbl for
the year ended December 31, 2023 compared to USD 94 per bbl for the comparative period and the average discount to WCS
used in IPC’s pricing formula was USD 19 per bbl compared to USD 18 per bbl for the comparative period.
The realized sales price for Malaysia and France is based on Brent crude oil prices and the average market Brent crude oil price
was USD 83 per bbl for the year ended December 31, 2023 compared to USD 101 per bbl for the comparative period.
Gas and NGL sales
Three months ended – December 31, 2023
Canada –
Southern Assets
Canada –
Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 14,983 118 15,101
- Quantity sold in Mcf 8,585,805 77,185 8,662,990
- Average price realized USD per Mcf 1.75 1.53 1.74
Three months ended – December 31, 2022
Canada –
Southern Assets
Canada –
Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 35,798 256 36,054
- Quantity sold in Mcf 8,256,010 70,093 8,326,103
- Average price realized USD per Mcf 4.34 3.65 4.33
Gas and NGL sales revenue was 58% lower for Q4 2023 compared to Q4 2022 mainly due to the lower achieved gas price. IPC’s
achieved gas price is based on AECO pricing plus a premium. For Q4 2023, IPC realized an average price of CAD 2.33 per Mcf
compared to AECO average pricing of CAD 2.29 per Mcf.
Year ended – December 31, 2023
Canada –
Southern Assets
Canada –
Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 68,137 373 68,510
- Quantity sold in Mcf 33,221,660 227,032 33,448,692
- Average price realized USD per Mcf 2.05 1.64 2.05
Year ended – December 31, 2022
Canada –
Southern Assets
Canada –
Northern Assets Total
Gas and NGL sales
- Revenue in USD thousands 154,446 1,082 155,528
- Quantity sold in Mcf 32,699,017 264,673 32,963,690
- Average price realized USD per Mcf 4.72 4.09 4.72
Gas and NGL sales revenue was 56% lower for the year ended December 31, 2023 compared to the year ended December 31,
2022 mainly due to the lower achieved gas price.
IPC’s achieved gas price is based on AECO pricing plus a premium. For the year ended December 31, 2023, IPC realized an
average price of CAD 2.73 per Mcf compared to AECO average pricing of CAD 2.61 per Mcf.
18
===== SIDA 62 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Hedging settlement
IPC enters into risk management contracts in order to ensure a certain level of cash flow. It focuses mainly on oil and gas price
swaps to limit pricing exposure. The oil and gas pricing contracts are not entered into for speculative purposes.
The realized hedging settlement for the year ended December 31, 2023 amounted to a gain of USD 18,928 thousand and
consisted of a gain of USD 15,664 thousand on the gas contracts and a gain of USD 3,264 thousand on the oil contracts. Also see
the Financial Position and Liquidity and the Financial Risk Management sections below.
Production costs
Production costs including inventory movements amounted to USD 126,414 thousand for Q4 2023 compared to USD 125,631
thousand for Q4 2022 and USD 491,303 thousand for the year ended December 31, 2023 compared to USD 476,987 thousand for
the comparative period, and is analyzed as follows:
Three months ended – December 31, 2023
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other3 Total
Operating costs1 38,651 23,868 12,091 11,679 (2,921) 83,368
USD/boe2 14.80 16.39 51.74 45.26 n/a 18.28
Cost of blending 6,872 37,601 – – – 44,473
Change in inventory position (873) 638 (1,217) 25 – (1,427)
Production costs 44,650 62,107 10,874 11,704 (2,921) 126,414
Three months ended – December 31, 2022
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other3 Total
Operating costs1 32,964 23,247 13,534 8,900 (4,140) 74,505
USD/boe2 14.21 15.72 28.12 33.75 n/a 16.45
Cost of blending 7,040 39,494 – – – 46,534
Change in inventory position (124) 551 4,111 54 – 4,592
Production costs 39,880 63,292 17,645 8,954 (4,140) 125,631
Year ended – December 31, 2023
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other3 Total
Operating costs1 155,178 94,817 50,032 36,288 (14,353) 321,962
USD/boe2 15.51 16.33 35.87 36.27 n/a 17.63
Cost of blending 26,792 146,204 – – – 172,996
Change in inventory position (952) 448 (3,358) 207 – (3,655)
Production costs 181,018 241,469 46,674 36,495 (14,353) 491,303
19
===== SIDA 63 =====
Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Year ended – December 31, 2022
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Other3 Total
Operating costs1 115,574 101,443 51,476 35,589 (16,425) 287,657
USD/boe2 12.71 17.75 26.72 35.04 n/a 16.21
Cost of blending 33,797 155,375 – – – 189,172
Change in inventory position (317) (721) 1,916 (720) – 158
Production costs 149,054 256,097 53,392 34,869 (16,425) 476,987
1 See definition on page 24 under “Non-IFRS measures”.
2 USD/boe in the tables above is calculated by dividing the cost by the production volume for each country for the period and includes Cor4 from
January 1, 2023.
3 Included in the Malaysia operating costs is the lease cost for the FPSO Bertam which is owned by the Group. Other represents the FPSO Bertam
lease fee self-to-self payment elimination. Netting the self-to-self elimination against the operating costs in Malaysia reduces the operating costs
per boe for Malaysia to USD 39.24 and USD 19.52 for Q4 2023 and Q4 2022 respectively and USD 25.58 and USD 18.20 for the year ended
December 31, 2023 and December 31, 2022, respectively.
Operating costs
Operating costs amounted to USD 83,368 thousand for Q4 2023 compared to USD 74,505 thousand for Q4 2022 and USD
321,962 thousand for the year ended December 31, 2023 compared to USD 287,657 for the year ended December 31, 2022. The
increase in costs in 2023 compared to 2022 is due mainly to the Cor4 acquisition in Q1 2023, increased production and activity
levels. Operating costs per boe amounted to USD 18.28 per boe in Q4 2023 below guidance for the quarter and compared with
USD 16.45 per boe in Q4 2022. The operating cost per boe in Malaysia is higher in Q4 2023 compared with Q4 2022 as a result
of the lower production due to two producing wells offline. Operating costs per boe for the year ended December 31, 2023
amounted to USD 17.63 per boe which was within the full year operating cost guidance of between USD 17.5 to 18 per boe.
Cost of blending
For the Suffield area assets in Canada, oil production is blended with purchased condensate diluent to meet pipeline specifications.
As a result of the blending, actual sales volumes are higher than produced barrels and the realized sales price of a blended barrel
is higher than an unblended barrel. The majority of Onion Lake oil production has also been blended and exported by pipeline since
April 2022 with the commissioning of a third party export pipeline from the Onion Lake field to the gathering system.
The cost of the diluent amounted to USD 44,473 thousand for Q4 2023 compared to USD 46,534 thousand for Q4 2022 and USD
172,996 thousand for the year ended December 31, 2023 compared to USD 189,172 thousand for the comparative period. The
decrease versus the comparative period is largely attributable to lower commodity pricing reflected in the cost of diluent partly
offset by increased blending at Onion Lake following the commissioning of the pipeline in April 2022.
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 Q4 2023, IPC had crude entitlement of 163,000 barrels of oil on the FPSO Bertam facility
being crude produced but not yet sold. The next Bertam lifting scheduled for February 2024.
Depletion and decommissioning costs
The total depletion of oil and gas properties amounted to USD 30,434 thousand for Q4 2023 compared to USD 30,320 thousand
for Q4 2022 and USD 126,010 thousand for the year ended December 31, 2023 (including an adjustment for accelerated
decommissioning activities amounting to USD 24,088 thousand) compared to USD 122,041 thousand for the year ended
December 31, 2023. The depletion charge is analyzed in the following tables:
Three months ended – December 31, 2023
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Total
Depletion cost in USD thousands 14,654 9,165 2,982 3,633 30,434
USD per boe 5.61 6.30 12.76 14.08 6.67
Three months ended – December 31, 2022
USD Thousands Canada –
Southern Assets
Canada –
Northern Assets Malaysia France Total
Depletion cost in USD thousands 10,591 8,256 8,667 2,806 30,320
USD per boe 4.57 5.58 18.01 11.22 6.69
20
===== SIDA 64 =====