Kvartalsrapport Q4 2023

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Year ended – December 31, 2023
USD Thousands Canada –
Southern Assets
Canada –
 Northern Assets Malaysia France Total
Depletion cost in USD thousands 56,897 37,295 17,800 14,018 126,010
USD per boe 5.68 6.42 12.76 14.01 6.89
Year ended – December 31, 2022
USD Thousands Canada –
Southern Assets
Canada –
 Northern Assets Malaysia France Total
Depletion cost in USD thousands 41,980 33,097 34,687 12,277 122,041
USD per boe 4.62 5.79 18.01 12.13 6.88
1  In Canada, excludes the adjustment for accelerated decommissioning activities.
2  USD/boe in the tables above is calculated by dividing the depletion cost by the production volume for each country for the period and includes 
Cor4 from January 1, 2023.
The depletion charge is derived by applying the depletion rate per boe to the volumes produced in the period by each field. The 
depletion rate in Malaysia has significantly decreased compared to the prior year following the extension to the Bertam field 
production sharing contract and consequent increase in field reserves announced at the end of 2022. In addition, the depletion rate 
in Canada - Southern Assets has increased compared to the prior year as a result of the Cor4 acquisition.
Depreciation of other tangible fixed assets
The total depreciation of other assets amounted to USD 1,309 thousand for Q4 2023 compared to USD 2,695 thousand for Q4 
2022 and USD 7,812 thousand for the year ended December 31, 2023 compared to USD 10,787 thousand for the comparative 
period. This relates to the depreciation of the FPSO Bertam, which is being depreciated on a unit of production basis to August 
2025, being the original Bertam field production sharing contract (PSC) expiry date, before the PSC extension to 2035.
Exploration and business development costs
The total exploration and business developments costs amounted to a cost of USD 348 thousand for Q4 2023 and a cost of USD 
2,355 thousand for the year ended December 31, 2023 including Cor4 acquisition related costs amounting to USD 834 thousand.
Sale of assets
Sale of assets amounted to USD 19,018 thousand for the year ended December 31, 2023 and represents the sale of John Lake 
properties in Canada with 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). 
Net financial items
Net financial items amounted to a charge of USD 22,736 thousand for the year ended December 31, 2023, compared to a charge 
of USD 37,131 thousand for the year ended December 31, 2022, and included a non-cash net foreign exchange loss of USD 1,911 
thousand for 2023 compared to a net foreign exchange loss of USD 7,872 thousand for 2022. The foreign exchange movements 
during the year ended December 31, 2023 are mainly resulting from the revaluation of intra-group loan funding balances.
Excluding foreign exchange movements, the net financial items amounted to a charge of USD 20,825 thousand for the year ended 
December 31, 2023, compared to USD 29,259 thousand for the year ended December 31, 2022.  
The interest expense amounted to USD 25,635 thousand for the year ended December 31, 2023, compared to USD 20,689 
thousand for the comparative period in 2022 and mainly related to the bond interest at a coupon rate of 7.25% per annum. Interest 
income generated on cash balances held in 2023 amounted to USD 21,774 thousand for the year ended December 31, 2023 and is 
higher than the comparative period of USD 6,966 thousand due mainly to higher interest rates and higher cash balances.
The unwinding of the asset retirement obligation discount rate amounted to USD 13,408 thousand for year ended December 31, 
2023, compared to USD 10,758 thousand for the year ended December 31, 2022.
Income tax
The corporate income tax amounted to a charge of USD 55,362 thousand for the year ended December 31, 2023, compared to a 
charge of USD 127,413 thousand for the year ended December 31, 2022 and has decreased due to the lower net financial result 
before tax. 
The current income tax charge amounted to USD 14,457 thousand in 2023 compared to USD 29,365 thousand in 2022 and mainly 
related to France and Malaysia. The current income tax charge included a windfall profits tax in France amounting to USD 10,915 
thousand. No corporate income tax was payable in Canada in respect of the year ended December 31, 2023 due to the usage of 
historical tax pools. 
21

===== SIDA 65 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Capital Expenditure
Development and exploration and evaluation expenditure incurred during the year ended December 31, 2023 was as follows:
USD Thousands Canada –
Southern Assets
Canada –
 Northern Assets Malaysia France Total
Development 23,454 255,159 17,873 16,204 312,690
Exploration and evaluation – – – 39 39
23,454 255,159 17,873 16,243 312,729
Capital expenditure of USD 312,729 thousand was mainly spent in Canada on the Blackrod Phase 1 Development project and on 
the Pad L completion at Onion Lake Thermal, in France on the drilling of the Villeperdue West oil wells and in Malaysia on the well 
workovers.
In addition, USD 5,821 thousand of capital expenditure was spent on the Brooks assets mainly on drilling from January 1, 2023 to 
the completion date of March 3, 2023.
Cor4 Acquisition
On March 3, 2023, IPC completed the acquisition of all of the issued and outstanding shares of Cor4 Oil Corp. (“Cor4”). Cor4 
owned assets in the Brooks area, Alberta. At such date, Cor4 became an indirect wholly-owned subsidiary of IPC. On June 1, 
2023, Cor4 was amalgamated into IPC Canada Ltd.
The Cor4 acquisition has been accounted for as a business combination with IPC being the acquirer, and in accordance with IFRS 3 
Business Combinations, the assets acquired and liabilities assumed have been recorded at their fair values. 
Total cash consideration paid, after preliminary closing adjustments, amounted to USD 62.2 million (CAD 84.7 million).
The amounts recognized in respect of the identifiable assets acquired and liabilities assumed are as set out in the table below.
USD Thousands
Cash 2,792
Trade and other receivables  7,671 
Prepaid expenses and deposits  2,417 
Fair value of risk management assets  1,144 
Deferred tax assets  19,334 
Right-of-use assets  109 
Property, plant and equipment  72,242
Accounts payable and accrued liabilities  (12,623)
Right-of-use liabilities  (109)
Decommissioning liabilities  (29,885)
Mark-To-Market reserve in equity  (881)
Total Consideration 62,211
Settled by:
Cash payment 62,211
The Corporation performed a preliminary purchase price allocation for the Cor4 acquisition. The amounts disclosed above were 
determined provisionally pending the finalization of the valuation for those assets and liabilities. Up to twelve months from the 
effective date of the Cor4 acquisition, further adjustments may be made to the fair values assigned to the identifiable assets 
acquired and liabilities assumed. 
Acquisition-related costs of approximately USD 0.8 million have been recognized in the statement of operations during the year 
ended December 31, 2023.
 
22

===== SIDA 66 =====

Management’s Discussion and Analysis
For the three months ended and 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%.
Other tangible fixed assets
Other tangible fixed assets amounted to USD 25,438 thousand as at December 31, 2023, which included USD 23,730 thousand in 
respect of the FPSO Bertam. The FPSO Bertam is being depreciated on a unit of production basis based to August 2025, being the 
original Bertam field PSC expiry date before the PSC extension to 2035.
Financial Position and Liquidity
Financing 
As at January 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 from CAD 75 to CAD 150 million and extended the maturity to May 2025. In 
Q3 2023, the Group 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.
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).
Total net cash as at December 31, 2023 amounted to USD 58 million.
IPC intends to fund the Blackrod Phase 1 development with cash on hand, forecast FCF generated by its operations and available 
credit facilities.
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.
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.
Cash and cash equivalents held amounted to USD 517 million as at December 31, 2023.
Working Capital 
As at December 31, 2023, the Group had a net working capital balance including cash of USD 487,709 thousand compared to 
USD 488,661 thousand as at December 31, 2022. The difference as at December 31, 2023, from December 31, 2022 is mainly 
as a result of the increased cash following the tap issue offset by the payment for the Cor4 acquisition and the continuing NCIB 
program. 
23

===== SIDA 67 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Non-IFRS Measures
In addition to using financial measures prescribed under IFRS, references are made in this MD&A to “operating cash flow”, “free
cash flow”, “EBITDA”, “operating costs” and “net debt”/”net cash”, which are non-IFRS measures. Non-IFRS measures do 
not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by 
other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in 
accordance with IFRS.
The Corporation uses non-IFRS measures to provide investors with supplemental measures to assess cash generated by and
the financial performance and condition of the Corporation. Management also uses non-IFRS measures internally in order to
facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Group’s
ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures
are important supplemental measures of operating performance because they highlight trends in the core business that may
not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for
assessment of the Group’s operating performance and financial condition on a basis that is more consistent and comparable
between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties
frequently use non-IFRS measures in the evaluation of public companies. Forward-looking statements are provided for the
purpose of presenting information about management’s current expectations and plans relating to the future and readers are
cautioned that such statements may not be appropriate for other purposes.
“Operating cash flow” is calculated as revenue less production costs less current tax. Operating cash flow is used to analyze the
amount of cash that is being generated available for capital investment and servicing debt.
“Free cash flow” is calculated as operating cash flow less capital expenditures less decommissioning and farm-in expenditures
less general, administration and depreciation expenses before depreciation and less cash financial items. Free cash flow is used
to analyze the amount of cash that is being generated by the business and that is available for such purposes as repaying debt,
funding acquisitions and returning capital to shareholders.
“EBITDA” is calculated as net result before financial items, taxes, depletion of oil and gas properties, exploration costs,
impairment costs and depreciation and adjusted for non-recurring profit/loss on sale of assets and other income.
“Operating cost” is calculated as production costs excluding any change in the inventory position and the cost of blending and is
used to analyze the cash cost of producing the oil and gas volumes.
“Net debt” is calculated as bank loans and bonds less cash and cash equivalents. “Net cash” is calculated as cash and cash 
equivalents less bank loans and bonds. 
Reconciliation of Non-IFRS Measures
Operating cash flow
The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended 
December 31
Year ended
December 31
2023 2022 2023 2022
Revenue 198,460 254,615 853,906 1,129,298 
Production costs (126,414) (125,631) (491,303) (476,986)
Current tax 1,588 (15,316) (14,457) (29,365)
Operating cash flow 73,634 113,668 348,146 622,947 
The operating cash flow for the year ended December 31, 2023 including the operating cash flow contribution of the Cor4 
acquisition from the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 353,048 
thousand. 
24

===== SIDA 68 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Free cash flow
The following table sets out how free cash flow is calculated from figures shown in the Financial Statements:
USD Thousands
Three months ended 
December 31
Year ended
December 31
2023 2022 2023 2022
Operating cash flow - see above 73,634 113,668 348,146 622,947 
Capital expenditures (128,825) (42,792) (312,729) (157,662)
Abandonment and farm-in expenditures1 (1,516) (1,085) (9,199) (6,962)
General, administration and depreciation expenses before 
depreciation2 (5,762) (3,333) (16,886) (12,832)
Cash financial items3 (2,219) (1,170) (5,812) (15,249)
Free cash flow (64,688) 65,288 3,520 430,242 
1  See note 20 to the Financial Statements 
2  Depreciation is not specifically disclosed in the Financial Statements
3  See notes 5 and 6 to the Financial Statements.
The free cash flow for the year ended December 31, 2023 including the free cash flow contribution of the Cor4 acquisition from 
the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 2,689 thousand. 
EBITDA
The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:
USD Thousands
Three months ended 
December 31
Year ended
December 31
2023 2022 2023 2022
Net result 29,710 61,183 172,979 337,725 
Net financial items 6,509 6,002 22,736 37,131 
Income tax 4,691 24,486 55,362 127,413 
Depletion 30,434 30,320 101,922 122,041 
Depreciation of other tangible fixed assets 1,309 2,695 7,812 10,787 
Exploration and business development costs 348 558 2,355 2,775 
Depreciation included in general, administration and depreciation 
expenses1 389 407 1,569 1,608 
Sale of assets (7,106) – (19,018) –
EBITDA 66,284 125,651 345,717 639,480 
1  Item is not shown in the Financial Statements.
The EBITDA for the year ended December 31, 2023 including the EBITDA contribution of the Cor4 acquisition from the effective 
date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 350,618 thousand. 
Operating costs
The following table sets out how operating costs is calculated: 
USD Thousands
Three months ended 
December 31
Year ended
December 31
2023 2022 2023 2022
Production costs 126,414 127,495 491,303 483,646 
Cost of blending (44,473) (46,534) (172,996) (189,172)
Change in inventory position 1,427 (4,592) 3,655 (158)
Operating costs 83,368 76,369 321,962 294,316 
The operating costs for the year ended December 31, 2023 including the operating costs contribution of the Cor4 acquisition from 
the effective date of January 1, 2023 to the completion date of March 3, 2023 amounted to USD 328,763 thousand. 
25

===== SIDA 69 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Net cash
The following table sets out how net cash is calculated: 
USD Thousands December 31, 2023 December 31, 2022
Bank loans (9,031) (12,142)
Bonds1 (450,000) (300,000)
Cash and cash equivalents 517,074 487,240 
Net cash 58,043 175,098 
1  The bond amount represents the redeemable value at maturity (February 2027).  
Off-Balance Sheet Arrangements
IPC, through its subsidiary IPC Canada Ltd, has issued four letters of credit as follows: (a) CAD 2.6 million in respect of its 
obligations to purchase diluent; (b) CAD 0.8 million in respect of its obligations related to the Ferguson asset, increasing by  
CAD 0.1 million annually to a maximum of CAD 1.0 million; (c) CAD 1.3 million in respect of pipeline access; and (d) CAD 0.5 
million in relation to the hedging of electricity prices. 
Outstanding Share Data 
The common shares of IPC 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.
Nemesia S.à.r.l., an investment company ultimately controlled by trusts whose settlor is the late Adolf H. Lundin, holds 40,697,533 
common shares in IPC, representing 32.0% of the outstanding common shares as at December 31, 2023.
In addition, IPC has 117,485,389 outstanding class A preferred shares, issued as a part of an internal corporate structuring to a 
wholly-owned subsidiary of IPC. Such preferred shares are not listed on any stock exchange and do not carry the right to vote on 
matters to be decided by the holders of IPC’s common shares.
IPC has 4,440,062 IPC Share Unit Plan awards outstanding as at February 6, 2024 (321,512 awards granted in March 2021, 
1,716,000 awards granted in May 2021, 4,333 awards granted in January 2022, 1,244,359 awards granted in March 2022, 2,391 
awards granted in July 2022, 2,072 awards granted in January 2023, 1,143,708 awards granted in March 2023, 3,244 awards 
granted in July 2023 and 2,443 awards granted in January 2024).
Contractual Obligations and Commitments 
In the normal course of business, the Group has committed to certain payments which are not recognised as liabilities. The
following table summarizes the Group’s commitments in Canada as at 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.
26

===== SIDA 70 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Critical Accounting Policies and Estimates
In connection with the preparation of the Corporation’s consolidated financial statements, management has made assumptions 
and estimates about future events and applied judgments that affect the reported values of assets, liabilities, revenues, expenses 
and related disclosures. These assumptions, estimates and judgments are based on historical experience, current trends and other 
factors that they believe to be relevant at the time the financial statements are prepared. The management reviews the accounting 
policies, assumptions, estimates and judgments to ensure that the financial statements are presented fairly in accordance with 
IFRS. However, because future events and their effects cannot be determined with certainty, actual results could differ from these 
assumptions and estimates, and such differences could be material.
Transactions with Related Parties 
During 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.
Financial Risk Management 
As an international oil and gas exploration and production company, IPC is exposed to financial risks such as interest rate risk,
currency risk, credit risk, liquidity risks as well as the risk related to the fluctuation in oil and gas prices. The Group seeks to control 
these risks through sound management practice and the use of internationally accepted financial instruments, such as oil and gas, 
condensate and electricity price, interest rate or foreign exchange hedges as the case may be. Financial instruments will be solely 
used for the purpose of managing risks in the business. As at December 31, 2023, the Corporation had entered into oil and gas, 
condensate and electricity price hedges – see below.
Management believes that the cash resources, other current assets and cash flow from operations are sufficient to finance the
Group’s operations and capital expenditures program over the next year.
Capital Management
The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern and to meet its
committed financial liabilities and work program requirements in order to create shareholder value. The Group may put in place
new bonds or credit facilities, repay debt, or pursue other such restructuring activities as appropriate.
Management of the Corporation will continuously monitor and manage the Group’s capital, liquidity and net debt position in order
to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility.
Price of Oil and Gas
Prices of oil and gas are affected by the normal economic drivers of supply and demand as well as by financial investors and 
market uncertainty. Factors that influence these prices include operational decisions, prices of competing fuels, natural disasters, 
economic conditions, transportation constraints, political instability or conflicts or actions by major oil exporting countries. Price 
fluctuations will affect the Group’s financial position. 
Based on analysis of the circumstances, management assesses the benefits of forward hedging monthly sales contracts for the 
purpose of protecting cash flow. If management believes that a hedging contract will appropriately help manage cash flow then it 
may choose to enter into a commodity price hedge. The Group does not currently have any covenants under its current financing 
facilities to hedge future production.
The Group had 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
27

===== SIDA 71 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
The Group had no gas price sale financial hedges outstanding as at December 31, 2023. 
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had 
a positive fair value of USD 28,291 thousand 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
The above hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. The hedges had 
a long term negative fair value of USD 202 thousand as at December 31, 2023.
Currency Risk
The Group’s policy on currency rate hedging is, in the case of currency exposure, to consider fixing the rate of exchange. The 
Group will take into account the currency exposure, current rates of exchange and market expectations in comparison to historic 
trends and volatility in making the decision to hedge.
In 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. The hedges had 
a positive fair value of USD 12,934 thousand as at December 31, 2023.
Interest Rate Risk
Interest rate risk is the risk to earnings due to uncertain future interest rates on borrowings. The Group will take into account the 
level of external debt, current interest rates and market expectations in comparison to historic trends and volatility in making the 
decision to hedge.
Credit Risk
The Group may be exposed to third party credit risk through contractual arrangements with counterparties who buy the Group’s 
hydrocarbon products. The Group’s policy is to limit credit risk by only entering into oil and gas sales agreements with reputable 
and creditworthy oil and gas and trading companies. Where it is determined that there is a credit risk for oil and gas sales, the 
Group’s policy is to require credit enhancement from the purchaser.
The Group’s policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take 
possession of the licence or the joint venture partner’s share of production for non-payment of cash calls or other amounts due. In 
addition, cash is to be held and transacted only through major banks.
RISK FACTORS 
IPC is engaged in the exploration, development and production of oil and gas and its operations are subject to various risks and 
uncertainties which include but are not limited to those listed below. The risks and uncertainties below are not the only ones 
that the Group faces. Additional risks and uncertainties not presently known to the Group or that the Group currently considers 
immaterial may also impair the business and operations of the Group and cause the price of the IPC’s common shares to decline. If 
any of the following risks actually occur, the Group’s business may be harmed and the financial condition and results of operations 
may suffer significantly.
See also “Cautionary Statement Regarding Forward-Looking Information” and “Reserves and Resources Advisory” below.
Non Financial Risks
Exploration, Development and Production Risks: Oil and gas operations involve many risks that even a combination of
experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Group
depends on its ability to find, acquire, develop and commercially produce oil and gas reserves. Without the continual addition
of new reserves, any existing reserves associated with the Group’s oil and gas assets at any particular time, and the production
therefrom, will decline over time as such existing reserves are exploited. There is a risk that additional commercial quantities
of oil and gas will not be discovered or acquired by the Group. Production delays and declines from normal field operating
conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.
Future oil and gas development may involve unprofitable efforts, not only from dry wells, but also from wells that are
productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs.
Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In
28

===== SIDA 72 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating
conditions may adversely affect the production from successful wells. These conditions include delays in obtaining
governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient
storage or transportation capacity or other geological and mechanical conditions. Production delays and declines from normal
field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to
varying degrees.
Oil and gas exploration, development and production operations are subject to all the risks and hazards typically associated
with such operations, including hazards such as fire, explosion, blowouts, cratering, hydrocarbon releases and spills, each of
which could result in substantial damage to oil and gas wells, production facilities, other property and the environment or
personal injury. In accordance with industry practice, the Group will not fully insure against all of these risks, nor are all such
risks insurable. The Group maintains liability insurance in an amount that it considers consistent with industry practice. Due
to the nature of these risks, however, there is a risk that such liabilities could exceed policy limits, in which event the Group
could incur significant costs.
Volatility in Oil and Gas Commodity Prices and Price Differentials: The marketability and price of oil and gas that may be
acquired or discovered by the Corporation is and will continue to be affected by numerous factors beyond its control. The
Corporation’s ability to market its oil and gas may depend upon its ability to access space on pipelines that deliver oil and gas
to commercial markets. The Corporation may also be affected by deliverability uncertainties related to the proximity of its
reserves to pipelines and processing and storage facilities, the capacity of such pipelines and facilities, and operational
problems affecting such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties,
land tenure, allowable production, the export of oil and gas and many other aspects of the oil and gas business.
Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for
oil and gas, market uncertainty and a variety of additional factors beyond the control of the Corporation. These factors include
economic conditions in Europe, Asia, the United States, Canada and elsewhere, the actions of OPEC and OPEC+, strategic
petroleum reserve (SPR) management by the United States, the conflict in Ukraine, the impact of pandemics (including Covid19), 
governmental regulation, political instability in the Middle East and elsewhere, the foreign supply of oil and gas, risks of
supply disruption, the price of foreign imports and the availability of alternative fuel sources.
Oil and gas prices have fluctuated widely during recent years and may continue to be volatile in the future. Any substantial
and extended decline in the price of oil and gas would have an adverse effect on the carrying value of the reserves and
resources, borrowing capacity, revenues, profitability and cash flows associated with the Group’s assets and may have a
material adverse effect on the business, financial condition, results of operations and prospects associated with the Group’s
assets.
The Group’s financial performance also depends on revenues from the sale of commodities which differ in quality and location
from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials in Canada
between the Group’s heavy crude oil (in particular the heavy crude oil differential) and quoted market prices. The market price
for heavy crude oil and bitumen in Canada is generally lower than market prices for light oil, due principally to the higher costs
associated with refining a barrel of heavy crude oil and higher transportation costs (diluent is required to be purchased and
blended with heavy crude oil to transport on most pipelines). Heavy crude oil differentials are also influenced by other factors
such as capacity and interruptions, refining demand and the quality of the oil produced, all of which are beyond the Group’s
control. It is difficult to predict future price differentials and any increase in heavy crude oil differentials could have an adverse
effect on the Group’s business, financial condition, results of operations and cash flows.
In addition, there has not been, at times, sufficient pipeline capacity to export all Canadian crude oil and the availability of
alternative transport capacity is more expensive and variable, therefore, the price for Canadian crude oil is very sensitive to
pipeline and refinery outages. This has resulted in significantly lower prices being realized by Canadian producers compared
with the WTI price and the Brent price for crude oil. In addition, the pro-rationing of capacity on inter-provincial pipeline systems
continues to affect the ability to export oil and gas from Canada. There can be no certainty that current investment in pipelines
will provide sufficient long-term export capacity or that currently operating systems will remain in service. There is also no
certainty that short-term operational constraints on pipeline systems, arising from pipeline interruption, refinery outages and/or
increased supply of crude oil, will not occur.
In order to transport crude oil production in Canada to sales markets, the Group is required to meet certain pipeline
specifications. Heavy crude oil and bitumen is usually blended with a lighter hydrocarbon (commonly referred to as diluent) to
increase its flow characteristics. The cost of diluent is generally correlated to crude oil prices. A shortfall in the supply of
diluent may cause its price to increase which would adversely affect the Group’s financial position and cash flow.
Climate Change: Climate change issues are an important factor for the oil and gas industry.
Transition Risks
The Group’s facilities and operations, and the oil and gas that the Group markets, result in the emission of greenhouse gas
(GHG) which makes the Group subject to GHG emissions legislation and regulation. Governments continue to evaluate and
implement policy, legislation, and regulations focused on restricting GHG emissions commonly and promoting adaptation to
climate change and the transition to a low-carbon economy. It is not possible to predict what measures governments may
implement in this regard, nor is it possible to predict the requirements that such measures may impose or when such
29

===== SIDA 73 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
measures may be implemented. Given the evolving nature of climate change policy and the control of GHG emissions and
resulting requirements, including carbon taxes and carbon pricing schemes implemented by varying levels of government, it
is expected that current and future climate change regulations will have the effect of increasing the Group’s operating
expenses, and, in the long-term, potentially reducing the value of oil and gas assets.
Regulatory climate change related risks arise from increased or amended environmental regulation. A breach of such
regulations may result in the imposition of fines or issuance of clean up orders in respect of the Group or the Group’s assets,
some of which may be material. Furthermore, management of the Corporation believes the political climate appears to favour
new programs for environmental laws and regulation, particularly in relation to the reduction of, or limitations on, GHG emissions 
or emissions intensity. There is a risk that any such programs, laws or regulations, if proposed and enacted, may contain emission 
reduction targets which will require substantial capital investments to adapt processes in place or lead to financial penalties or 
charges as a result of the failure to meet such targets.
Climate change policy is evolving at regional, national and international levels, and political and economic events may
significantly affect the scope and timing of climate change measures that are ultimately put in place. Implementation of
strategies by any level of government within the countries in which the Corporation operates, and whether to meet
international agreed limits, or as otherwise determined, for reducing GHGs could have a material impact on the operations
and financial condition of the Corporation. Increased scrutiny of applications for oil and gas licenses, permits and
authorizations to develop assets and projects could lead to delay, limit or prevent future development of assets or affect the
productivity of assets and the costs associated.
In addition, concerns about climate change and public discussion that oil and gas operations may be associated with climate 
change have resulted in a number of environmental activists and members of the public opposing the continued exploitation,
transportation and development of fossil fuels. Given the evolving nature of the debate related to climate change and the
control of GHGs and resulting requirements, it is not possible to predict the impact on the Group and its operations and
financial condition.
Emission and carbon tax regulations in Canada federally and regionally are evolving and as these regulations are established
or amended, they may have an impact on organizations involved in oil and gas production. Canada has taken steps to address
climate change by establishing the Canadian Net-Zero Emissions Accountability Act that enshrines in law the Government of
Canada’s commitment to achieve net-zero GHG emissions by 2050. In December 2023, the Government of Canada introduced 
draft regulations to cap oil and gas emissions by 2030 at levels 20% to 23% below 2019 levels (with the use of offsets) and 35% 
to 38% (without the use of offsets). The draft regulations are expected to be released in mid-2024 with final regulations in 2025. 
The regulations would be effective January 1, 2026. It is difficult to assess the overall impact these regulations will have on the 
Group at this time but it could result in increased costs to comply, delays in having projects approved and potentially a reduction in 
demand for oil from these regions, all of which could have a material negative impact on the Group’s business.
The International Sustainability Standards Board (“ISSB”) was created on November 3, 2021 with the aim to develop globally 
consistent, comparable and reliable sustainability disclosure standards. On June 26, 2023, the ISSB issued IFRS S1 “General 
Requirements for Disclosure of Sustainability-related Financial Information” and IFRS S2 “Climate-related Disclosures”. The 
Corporation is actively evaluating the potential effects of the ISSB issued sustainability standards; however, at this time, the 
Corporation is not able to determine the impact on future financial statements, nor the potential costs to comply with these 
sustainability standards.
Physical Risks
Physical climate change related risks can be event-driven with increased severity of extreme weather events, such as
cyclones, hurricanes, wildfires, droughts or floods, or long-term shifts in climate patterns with sustained higher temperatures,
water stress or sea level rise. These physical risks may have financial and operational implications for the Group, such
as direct damage to assets and indirect impacts from supply chain disruption to the delivery of goods and services. Certain of
IPC’s oil and gas assets are in locations that are proximate to forests and rivers and a wildfire or flood may lead to significant
downtime and/or damage.
Reputational Risks: Reputational risks arise from the surge of societal pressure on the fossil fuel industry in relation to its
contribution to global GHG emissions. Maintaining a positive reputation in the eyes of investors, regulators, communities,
employees and the general public is an important aspect for the success of the Corporation. Negative impact on the industry
and the Corporation’s reputation could result in the long-term delays in obtaining regulatory approvals, increased operating
costs, lower shareholder confidence, or availability of insurance and financing.
Oil and gas operations may be subject to public opposition. Such public opposition could result in higher costs, delays or even
project cancellations due to increased pressure on governments and regulators by special interest groups including Indigenous
groups, landowners, environmental groups and other organizations, blockades, legal or regulatory actions or challenges,
increased regulatory oversight, reduced support of governments, delays in, challenges to, or the revocation of regulatory
approvals, permits and/or licenses, and direct legal challenges, including the possibility of climate-related litigation. 
Project Risks: The Group is undertaking various projects, including Phase 1 of the Blackrod project. Project interruptions may
delay expected revenues from operations. Significant project cost overruns could make a project uneconomic. IPC’s ability to
execute projects depends upon numerous factors beyond its control, including: processing, pipeline and storage capacity, 
availability of water, electricity, gas, diluent and other operational supplies, effects of weather, availability of personnel and
30

===== SIDA 74 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
equipment, unexpected cost increases, accidents, regulatory and third party approvals and commercial arrangements,
stakeholder consultations (including Indigenous consultation) and regulatory changes (including carbon tax). As a result of
these and other factors, the Group may be unable to execute projects on time, on budget, or at all.
Inflationary Pressures and Costs: The Group’s operating costs could escalate and make operations unprofitable due to
supply chain disruptions, inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, and
additional government intervention. Labour costs, abandonment, reclamation, gas, electricity, water, diluent and chemicals
are examples of some of the operating and other costs that are susceptible to significant fluctuation. The inability to manage
costs may impact project returns and future development decisions, which could have an adverse effect on financial
performance. The cost or availability of oil and gas field equipment may adversely affect IPC’s ability to undertake projects.
The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services. These materials
and services may not be available when required at reasonable prices. A failure to secure the services and equipment
necessary to operations or projects for the expected price, on the expected timeline, or at all, may have an adverse effect on
financial performance.
The Group’s financial performance is significantly affected by the cost of operating and the capital costs associated with its assets. 
Operating and capital costs are affected by a number of factors including, but not limited to inflationary price pressure, scheduling 
delays, failure to maintain quality construction standards and supply chain disruptions. Fluctuations in operating and capital costs 
could negatively impact the Group’s business, financial condition, results of operations, cash flows and value of its oil and gas 
reserves.
Operational Risks Relating to Facilities and Pipelines: The pipelines and facilities associated with the Group’s assets, are
exposed to operational risks that can lead to hydrocarbon releases, production interruptions and unplanned outages. Other
operating risks relating to the facilities and pipelines associated with the Group’s assets include: the breakdown or failure of
equipment; breakdown or malicious attacks on information systems or processes; the performance of equipment at levels
below those originally intended; operator error; disputes and other issues with interconnected facilities; and catastrophic
events such as natural disasters, fires, explosions, acts of terrorists and saboteurs and other similar events, many
of which will be beyond the control of the Group. The occurrence or continuance of any of these or other operational events
could curtail sales or production or materially increase the cost of operating the facilities and pipelines associated with the
Group’s oil and gas assets and reduce revenues accordingly.
Reductions in Demand for Oil and Gas: Increasing consumer demand for alternatives to oil and gas, conservation measures,
alternative fuel requirements, and technological advances in fuel economy and renewable energy generation systems, could
reduce the demand for oil and gas. Some jurisdictions have implemented policies or incentives to decrease the use of fossil
fuels and to encourage the use of renewable fuel alternatives, which could reduce the demand for oil and gas. Advancements
in energy efficient products have a similar effect on the demand for oil and gas. The Corporation cannot predict the impact of
changing demand for oil and gas products, and any major changes may have an adverse effect on IPC’s business, financial
condition, results of operations and cash flow from operations by decreasing increasing costs, limiting access to capital and
decreasing the value of oil and gas assets.
Uncertainties Associated with Estimating Reserves and Resources Volumes: There are numerous uncertainties inherent 
in estimating quantities of oil and gas reserves and resources (contingent and prospective) and the future cash flows attributed 
to such reserves and resources. The cash flow information associated with reserves and resources set forth in this MD&A 
are estimates only. The actual production, revenues, taxes and development and operating expenditures with respect to the 
reserves and resources associated with the Group’s assets will vary from estimates thereof and such variations could be material. 
Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon 
analogy to similar types of reserves rather than actual production history. There is uncertainty that it will be commercially viable to 
produce any portion of the contingent resources
In accordance with applicable securities laws, the Corporation and the Corporation’s independent reserves auditors have used
forecast prices and costs in estimating the reserves, resources and future net cash flows as summarized herein. Actual future
net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and gas,
curtailments or increases in consumption by oil and gas purchasers, changes in governmental regulation or taxation and the
impact of inflation on costs.
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.
References to “prospective resources” do not constitute, and should be distinguished from, references to “contingent
resources” and “reserves”. This MD&A contains estimates of the net present value of the future net revenue from IPC’s reserves
and resources. The estimated values of future net revenue disclosed in this MD&A do not represent fair market value. There is
no assurance that the forecast prices and cost assumptions used in the reserves and resource evaluations will be attained and
variances could be material. See also “Reserves and Resources Advisory” below.
SAGD Recovery Process: : The Group has implemented a SAGD recovery process at the Onion Lake Thermal project and the 
Blackrod project. The SAGD recovery process requires a significant amount of gas or other fuels to produce steam for use in the 
recovery process. The amount of steam required in the production process can vary and impact costs significantly. The quality and 
performance of the reservoir can impact the timing, cost and levels of production using this technology. There can be no assurance 
that the Group’s operations will produce at the expected levels or on schedule. In addition, a significant amount of water is used 
in SAGD operations. Government regulations apply to access to and use of water. Any shortages in water supplies could lead to 
increased costs and have a material adverse effect on results of operation and financial condition.
31

===== SIDA 75 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Hydraulic Fracturing: Hydraulic fracturing involves the injection of water, sand, and small amounts of additives under high
pressure into tight rock formations that were previously unproductive to stimulate the production of oil and gas. Concerns
about seismic activity, including earthquakes, caused by hydraulic fracturing has resulted in regulatory authorities implementing
additional protocols for areas that are prone to seismic activity or completely banning hydraulic fracturing in other areas. Any
new laws, regulations, or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased
operating costs, third party or governmental claims, and could increase costs of compliance, as well as delay development of
certain oil and gas resources. Restrictions or bans on hydraulic fracturing could result in restricting the economic recovery of
oil and gas reserves. In addition, the Group may need to dispose of the fluids produced from oil and gas production operations,
including produced water. The legal requirements related to the disposal of produced water into a non-producing geologic
formation by means of underground injection wells are subject to change based on concerns of the public or governmental
authorities regarding such disposal activities.
Regulatory Approvals and Compliance and Changes in Legislation and the Regulatory Environment: Oil and gas operations 
(including exploration, development, production, pricing, marketing and transportation) are subject to extensive controls and 
regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate 
or intervene with respect to exploration, production and abandonment activities, price, taxes (including carbon taxes), GHG 
emission restrictions, royalties and the export of oil and gas. The implementation of new regulations or the modification of 
existing regulations affecting the oil and gas industry could reduce demand for oil and gas and increase the costs associated 
with the Group’s oil and gas assets, any of which may have a material adverse effect on the business, financial condition, results 
of operations and prospects of the Group’s oil and gas assets. In order to conduct oil and gas operations, the Group will require 
regulatory permits, licences, registrations, approvals, authorizations and concessions from various governmental authorities. There 
is a risk that the permits, licences, registrations, approvals, authorizations and concessions currently granted to the Group will 
not be renewed or that the Group will be unable to obtain all of the permits, licences, registrations, approvals, authorizations and 
concessions that may be required to conduct operations that it may wish to undertake.
The French government has enacted legislation to cease granting new petroleum exploration licences in France and to restrict
the production of oil and gas under existing production licences in France from 2040. There is a risk that France could
implement further legislative changes and that the licence regime in France could become more onerous. In Canada, the oil
and gas regulatory authorities have implemented regulations regarding the ability to transfer leases, licences, permits, wells
and facilities between parties. These authorities have increased the minimum abandonment liability rating of the buyer before
they will accept a transfer of oil and gas assets. These regulations may make it difficult and costly for producers, such as IPC,
to transfer or sell assets to other parties.
Change in governments or policies in the countries in which the Group operates may have an impact on the decisions taken
and regulations made by such governments on matters that may impact the oil and gas industry including the balance
between economic development and environmental policy. The oil and gas industry has become an increasingly political
topic, which has resulted in a rise in activism and criticism surrounding oil and gas development, particularly with respect to
infrastructure projects. Protests, blockades and demonstrations have the potential to delay and disrupt the Group’s activities.
Indigenous Land and Rights Claims: In Canada, Indigenous groups have filed claims in respect of their indigenous and
treaty rights against the federal and certain provincial governments as well as private individuals and companies. Consultation
delays, claims or objections related to Indigenous rights may disrupt or delay operations, new development or new project 
approvals on the Group’s properties. The Group is not aware of any claims made with respect to its properties or assets; 
however; if a claim arose and was successful, it may have a material adverse effect on the Group’s business, financial condition, 
results of operation and prospects. The majority of the Group’s interests at Onion Lake are situated on traditional reserve lands 
and are subject to the federal rules and regulations of Indian Oil and Gas Canada as well as of the Onion Lake Cree Nation of 
Saskatchewan/Alberta. There are risks associated with the management of the Group’s interests on these lands, including access 
and lease terms.
The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions
that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain circumstances, accommodate their
concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often
the subject of litigation. The fulfilment of the duty to consult Indigenous people and any associated accommodations may
adversely affect the Group’s ability to, or increase the timeline to, obtain or renew, permits, leases, licences and other
approvals, or to meet the terms and conditions of those approvals, or to advance project development, including Phase 1 of the 
Blackrod project.
Change of Control under Licences: The licence areas associated with the Group’s oil and gas assets require government
consent or compliance with regulations imposed by oil and gas regulatory authorities to effect a change of control of the
owner or an assignment of the ownership interest in the licence area. There may also be contractual restrictions on assignment
and change of control, including in the Suffield area of Canada where certain operations are conducted within a Canadian
Forces Base under access agreements with Canadian federal government and the Alberta provincial government. Accordingly,
should the Group propose to dispose of assets or if there is a change of control of the Corporation, consent may be required
in order to remain in compliance with the applicable licences and concessions. The failure to obtain such consent may have a
material adverse effect on the Corporation. Further, the requirement to obtain such consent may limit the ability of a third
party to effect a change of control transaction with the Corporation.
32

===== SIDA 76 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Failure to Realize Anticipated Benefits of Acquisitions and Dispositions: The Group may make acquisitions and
dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in
part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as
well as the Group’s ability to realize the anticipated growth opportunities and synergies from combining the acquired
businesses and operations with those of the Group. In addition, non-core assets may be periodically disposed of, so that the
Group can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets,
certain non-core assets of the Group, if disposed of, could be expected to realize less than their carrying value on the financial
statements of the Group.
Reliance on Third Party Infrastructure: The Group delivers the products associated with the Group’s assets by gathering,
processing and pipeline systems, most of which it does not own. The amount of oil and gas that the Group is able to produce
and sell is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems.
The lack of availability of capacity in any of the gathering, processing and pipeline systems, and in particular the processing
facilities, could ceased refining and result in the Corporation’s inability to realize the full economic potential of its production
or in a reduction of the price offered for the Corporation’s production or increased operating or transportation costs. Any
significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any
delays in constructing new infrastructure systems and facilities could harm the Group’s business financial condition, results
of operations, cash flows and future prospects.
Credit Facilities and Bonds: The Group is, and may in the future become, party to credit facilities with international financial
institutions. The Corporation has also issued bonds and may issue further bonds in the future. The terms of these facilities
and bonds may contain operating and financial covenants and restrictions on the ability of the Group to, among other things,
incur or lend additional debt, pay dividends and make restricted payments, encumber its assets, sell assets and enter into
certain merger or consolidation transactions. The failure of the Group to comply with the covenants contained in these
facilities and bonds could result in an event of default, which could, through acceleration of debt, enforcement of security or
otherwise, materially and adversely affect the operating results and financial condition of the Group.
In addition, the maximum amount that the Group is permitted to borrow under its credit facilities may be subject to periodic
review by the lenders. The Group’s lenders generally review its oil and gas production and reserves, forecast oil and gas
prices, general business environment and other factors to establish the amount which the Group is entitled to borrow. In the event 
the lenders decide to reduce the amount of credit available under the credit facilities, the Group may not have the ability to borrow 
funds under such facilities or may be required to repay all or a portion of the amounts owing thereunder.
If the Group fails to comply with the covenants in these facilities and bonds, is unable to repay or refinance amounts owned
at maturity or pay the debt service charges or otherwise commit an event of default, such as bankruptcy, it could result in
the seizure and/or sale of the Group’s assets by the creditors. The proceeds from any sale of the Group’s assets would be
applied to satisfy amounts owed to the secured creditors and then unsecured creditors. Only after the proceeds of that sale
were applied towards the Group’s debt would the remainder, if any, be available for the benefit of shareholders.
Credit Ratings: Credit ratings affect the Corporation’s ability to obtain short term and long term financing and the cost of
such financing. A reduction in the current rating or a negative change in the rating outlook could adversely affect the cost of
financing and access to sources of liquidity and capital. Any rating may not remain in effect for any given period of time or
may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant. Credit
ratings are not recommendations to buy, sell or hold any of the Corporation’s securities.
Competition for Resources and Markets: The international oil and gas industry is competitive in all its phases. The Group
competes with numerous other organizations in the search for, and the acquisition of, oil and gas properties and in the
marketing of oil and gas. The Corporation’s competitors include oil and gas companies that may have substantially greater
financial resources, staff and facilities than those of the Corporation. The Corporation’s ability to increase its reserves and
resources in the future depends not only on its ability to explore and develop its present properties, but also on its ability to
select and acquire other suitable producing properties or prospects for exploratory and development drilling. Competitive
factors in the distribution and marketing of oil and gas include price and methods and reliability of delivery and storage.
Competition may also be presented by alternate fuel sources and renewable energies.
Marketing: A decline in the Group’s ability to market oil and gas production could have a material adverse effect on its
production levels or on the price that the Group receives for production, which in turn may affect the financial condition of the
Corporation and the market price of the common shares. IPC’s business depends in part upon the availability, proximity and
capacity of oil and gas gathering systems, pipelines and processing facilities as well as, potentially, rail loading facilities and
railcars. Applicable regulation of oil and gas production, processing and transportation, tax and energy policies, general
economic conditions, and changes in supply and demand could adversely affect IPC’s ability to produce and market oil and
gas. If market factors change and inhibit the marketing of production, overall production or realized prices may decline, which
may affect the financial condition of the Corporation and the market price of the common shares.
Hedging Strategies: From time to time, the Group may enter into agreements to receive fixed prices on its oil and gas
production to offset the risk of revenue reductions if commodity prices decline; however, if commodity prices increase beyond
the levels set in such agreements, the Group will not benefit from such increases. Similarly, from time to time, the Group may
enter into agreements to fix the exchange rate of certain currencies. However, if a currency declines in value compared to
another currency, the Group may not benefit from the fluctuating exchange rate if an agreement has fixed such exchange rate.
33

===== SIDA 77 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Fraud, Bribery and Corruption: The operations relating to the Group’s oil and gas assets are governed by the laws of many
jurisdictions, which generally prohibit bribery and other forms of corruption. While the Corporation has implemented an anti-
corruption compliance program across the Group, the Corporation cannot guarantee that the Group’s employees, officers,
directors, agents, or business partners have not in the past or will not in the future engage in conduct undetected by the
processes and procedures to be adopted by the Corporation and for which the Corporation might be held liable under
applicable anti-corruption laws. Despite the Corporation’s compliance program and other related training initiatives, it is
possible that the Corporation, or some of its subsidiaries, employees or contractors, could be subject to an investigation
related to charges of bribery or corruption as a result of the unauthorized actions of its employees or contractors, which could
result in significant corporate disruption, onerous penalties and reputational damage.
Decommissioning, Abandonment and Reclamation Costs: The Group is responsible for compliance with all applicable laws, 
regulations and contractual requirements regarding the decommissioning, abandonment and reclamation of the Group’s
assets at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with
certainty since they will be a function of requirements at the time of decommissioning, abandonment and reclamation and
the actual costs may exceed current estimates. Laws, regulations and contractual requirements with regard to abandonment
and decommissioning may be implemented or amended in the future.
Third Party Credit Risk: The Group may be exposed to third party credit risk through the contractual arrangements associated
with the Group’s assets with its current or future joint venture partners, marketers of its petroleum and gas production, third
party uses of its facilities and other parties. In the event such entities fail to meet their contractual obligations in respect of
the Group’s assets, such failures may have a material adverse effect on the Group’s business, financial condition, results of
operations and prospects.
Repatriation of Earnings:  Jurisdictions in which the Group operates may implement measures to facilitate management of
foreign exchange risk. Such measures could restrict the Group’s ability to repatriate earning or other funds.
Expiration and Renewal of Licences, Leases and Production Sharing Contracts: : Certain of the Group’s oil and gas assets
are held in the form of licences, leases and production sharing contracts (PSCs). If the holder of the licence, lease or PSC or
the operator of the licence, lease or PSC fails to meet the specific requirement of a licence, lease or PSC, including compliance
with environmental, health and safety requirements, the licence, lease or PSC may terminate or expire. There is a risk that
the obligations required to maintain each licence, lease or PSC will not be met. The termination or expiration of the licence,
lease or PSC, or the working interests relating to a licence may have a material adverse effect on the business, financial
condition, results of operations and prospects associated with the Group’s oil and gas assets. From time to time, the licences
and leases may, in accordance with their terms, become due for renewal; there is a risk that these licences, leases and PSCs
associated with the Group’s oil and gas assets will not be renewed by the relevant government authorities on terms that will
be acceptable to the Corporation. There also can be significant delay in obtaining licence renewals which may already affect
the operations associated with the Group’s oil and gas assets.
Reliance on Third Party Operators: The Group has partners in some of the licence areas associated with the Group’s assets. In 
some cases, including in the Aquitaine Basin in France, the Group is not the operator of the licence and concession areas and must 
depend on the competence, expertise, judgment and financial resources (in addition to those of its own and, where relevant, other 
partnership and joint venture companies) of the partner operator and the operator’s compliance with the terms of the licences, 
leases and contractual arrangements. Mismanagement of licence areas by the Group’s partner operators or defaults by them in 
meeting required obligations may result in significant exploration, production or development delays, losses or increased costs to 
the Group.
Litigation: In the normal course of the Group’s operations, it may become involved in, named as a party to, or be the subject
of, various legal proceedings. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty
and may be determined adversely to the Group and as a result, could have a material adverse effect on the Group’s assets,
liabilities, business, financial condition and results of operations.
Terrorism and Sabotage: If any  of the properties, wells or facilities comprising the Group’s assets is the subject of terrorist
attack or sabotage, it may have a material adverse effect on the Group’s business, financial condition, results of operations,
cash flows and future prospects.
Information Security: The Group is dependent on its information systems and computer based programs. Failure,
malfunction or security breaches by computer hackers and cyberterrorists of any such systems or programs may have a
material adverse effect on the Group’s business and systems, potentially disrupting operations and affecting network assets
and people’s privacy. The Group manages cyber security risk by ensuring appropriate technologies, processes and practices
are effectively designed and implemented to help prevent, detect and respond to threats as they emerge and evolve. The Chief 
Operating Officer of the Corporation is principally responsible for overseeing cybersecurity risk management and for reporting 
such risks to other members of executive management and to the Board. The primary risks to the Group include, loss of data, 
destruction or corruption of data, compromising of confidential customer or employee information, leaked information, disruption 
of business, theft or extortion of funds, regulatory infractions, loss of competitive advantage and reputational damage.
34

===== SIDA 78 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Insurance: Although the Group maintains insurance in accordance with industry standards to address certain risks related to
oil and gas operations, such insurance has limitations on liability and may not be sufficient to cover the full extent of potential
liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, the Group may elect
not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons.
The payment of any uninsured liabilities would reduce the funds available to IPC. The occurrence of a significant event that
IPC is not fully insured against, or the insolvency of the insurer of such event, may have an adverse effect on IPC’s business,
financial condition, results of operations and prospects. The Group’s insurance policies are generally renewed on an annual
basis and, depending on factors such as market conditions, the premiums, policy limits and/or deductibles for certain insurance
policies can vary substantially. In some instances, certain insurance may become unavailable or available only for reduced
amounts of coverage.
Pandemics: The Covid-19 virus and the restrictions and disruptions related to it had a material effect on the world demand for, and 
prices of, oil and gas as well as the market price of the shares of oil and gas companies generally. There can be no assurance that 
these effects will not resume or that commodity prices will not decrease or remain volatile in the future due to Covid-19 or other 
pandemics. These factors are beyond the control of the Corporation, and it is difficult to assess how these, and other factors, will 
continue to affect the Corporation and the market price of IPC’s common shares.
Potential Conflicts of Interest: Certain of the individuals who are directors of the Corporation are also directors of other oil
and gas companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from
certain decisions.
Key Personnel: IPC’s success is in part dependent upon management, leadership capabilities and the quality and
competency of key personnel. If IPC is unable to retain key personnel and critical talent or to attract and retain new talent
with the necessary leadership, professional and technical competencies, it could have an adverse effect on the Group’s
financial condition, results of operations and prospects.
Change in Investors: Some institutional and other investors have announced that they no longer are willing to fund or invest
in oil and gas assets or companies, or are reducing the amount thereof over time. In addition, certain institutional investors
are requesting that issuers develop and implement more robust social, environmental and governance policies and practices.
Developing and implementing such policies and practices can involve significant costs and require a significant time
commitment from the Corporation. Failing to implement the policies and practices, as requested by institutional investors,
may result in such investors reducing their investment in the Corporation, or not investing in IPC at all.
Significant Shareholder:  Nemesia S.à.r.l., an investment company wholly owned by trusts whose settlor is the late Adolf
H. Lundin (“Nemesia”), owns approximately 32 percent of the aggregate common shares of the Corporation. Nemesia’s
holdings may allow it to significantly affect substantially all the actions taken by the shareholders of the Corporation, including
the election of directors. As long as Nemesia maintains a significant interest in the Corporation, it is likely that Nemesia will
exercise significant influence on the ability of the Corporation to, among other things, enter into a change in control transaction
of the Corporation and may also discourage acquisition bids for the Corporation. There is a risk that the interests of Nemesia
may not be aligned with the interests of other shareholders.
Financial Risks 
Management Estimates and Assumptions: In preparing consolidated financial statements in conformity with IFRS,
estimates and assumptions are used by management in determining the reported amounts of assets and liabilities, revenues
and expenses recognized during the periods presented and disclosures of contingent assets and liabilities known to exist as
of the date of the financial statements. These estimates and assumptions must be made because certain information that is
used in the preparation of such financial statements is dependent on future events, cannot be calculated with a high degree
of precision from data available, or is not capable of being readily calculated based on generally accepted methodologies. In
some cases, these estimates are particularly difficult to determine and the Corporation must exercise significant judgment.
Actual results for all estimates could differ materially from the estimates and assumptions used by the Corporation, which
could have a material adverse effect on the Group’s business, financial condition, results of operations, cash flows and future
prospects.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting: Effective disclosure controls and
procedures and internal controls over financial reporting are necessary for the Corporation to provide reliable financial and
other disclosures and to help prevent fraud. The Corporation cannot be certain that the procedures it undertakes to help
ensure the reliability of its financial reports and other disclosures, including those imposed on it under Canadian securities
laws, will ensure that it maintains adequate control over financial processes and reporting. Failure to implement required new
or improved controls, or difficulties encountered in their implementation, could harm the Group’s results of operations or
cause it to fail to meet its reporting obligations. If the Corporation or its independent auditor discover a material weakness,
the disclosure of that fact, even if quickly remedied, could reduce the market’s confidence in the Corporation’s consolidated
financial statements and harm the trading price of the common shares.
Income Taxes: Income tax laws relating to the oil and gas industry, such as the treatment of resource taxation or dividends
and the imposition of carbon taxes, may in the future be changed or interpreted in a manner that adversely affects the Group’s
assets. Furthermore, there is a risk that the relevant tax authorities will not agree with management’s calculation of the
income for tax purposes associated with the Group’s assets or that such tax authorities will change their administrative
practices to the detriment of the Corporation. In the event of a successful reassessment of the Corporation’s income tax
returns, such reassessment may have an impact on current and future taxes payable.
35

===== SIDA 79 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
In 2022, the EU imposed tax on energy companies deriving income from operations in EU countries (“Solidarity Contribution”). 
The Solidarity Contribution was applicable to the Group in France for the 2022 fiscal year. Such tax could be extended or increased 
in the future, and similar taxes may be levied in other jurisdictions in which the Group operates or proposes to operate.
Additional Funding Requirements: The Corporation’s cash flow from its reserves may not be sufficient to fund its ongoing
activities at all times. From time to time, the Corporation may require additional financing in order to carry out its oil and gas
acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause the
Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its
operations. If the Corporation’s revenues from its reserves decrease as a result of lower oil and gas prices or otherwise, it
will affect the Corporation’s ability to expend the necessary capital to replace its reserves or to maintain its production. If the
Corporation’s funds from operations is not sufficient to satisfy its capital expenditure requirements, there is a risk that debt
or equity financing will be unavailable to meet these requirements or, if available, will be on terms unacceptable to the
Corporation. Continued uncertainty in domestic and international credit markets could materially affect the Corporation’s
ability to access sufficient capital for its capital expenditures and acquisitions, and as a result, may have a material adverse
effect on the Corporation’s ability to execute its business strategy and on its business, financial condition, results of
operations and prospects and also negatively impact the market price of the common shares.
Variations in Foreign Exchange Rates and Interest Rates: World oil and gas prices are quoted in United States dollars and
are therefore affected by exchange rates, which will fluctuate over time. Future exchange rates could accordingly impact the
future value of the Corporation’s reserves and resources as determined by independent reserve auditors. To the extent that the
Corporation engages in risk management activities related to foreign exchange rates, there will be a credit risk associated
with counterparties of the Corporation. An increase in interest rates could result in a significant increase in the amount the
Corporation pays to service any debt that it may incur, which could negatively impact the market price of the common shares.
Issuance of Further Debt: From time to time,  the Corporation may enter into transactions to acquire assets or the shares of
other organizations. These transactions may be financed in whole or in part with debt, which may create debt or increase the
Corporation’s then-existing debt levels above industry standards for oil and gas companies of similar size. Depending on
future exploration and development plans, the Corporation may require additional equity and/or debt financing that may not
be available or, if available, may not be available on favorable terms. The level of the indebtedness that the Corporation may
have from time to time could impair the Corporation’s ability to obtain additional financing on a timely basis to take advantage
of business opportunities that may arise.
Common Share Price Volatility: The market price for common shares may be volatile and subject to wide fluctuations in 
response to numerous factors, many of which are beyond the Corporation’s control, including the following:
• Actual or anticipated fluctuations in the Corporation’s results of operations;
• Recommendations by securities research analysts;
• Changes in the economic performance or market valuations of other companies that investors deem comparable to the 
Corporation;
• The loss of executive officers and other key personnel of the Corporation;
• Issuances or perceived issuances of additional common shares;
• Significant acquisitions or business combinations, strategic partnerships, joint ventures or capital;
• Commitments by or involving the Corporation or its competitors; and
• Trends, concerns, technological or competitive developments, regulatory changes and other related issues in the 
Corporation’s business segments or target markets.
Financial markets can experience significant price and volume fluctuations that may particularly affect the market prices of
equity securities of companies and that may be unrelated to the operating performance, underlying asset values or prospects
of such companies. Accordingly, the market price of the common shares may decline even if the Corporation’s operating
results, underlying asset values or prospects have not changed. These factors, as well as other related factors, may cause
decreases in asset values, which may result in impairment losses.
DISCLOSURE CONTROLS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be 
disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation 
is recorded, processed, summarized and reported within the time periods specified in the securities legislation. Management, 
under the supervision of the Chief Executive Officer and the Chief Financial Officer, is responsible for the design and operation of 
disclosure controls and procedures.
Internal Controls over Financial Reporting
Management is also responsible for the design of the Group’s internal controls over financial reporting in order to provide reasonable 
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in 
accordance with IFRS. However, due to inherent limitations, internal control over financial reporting may not prevent or detect all 
misstatements and fraud. 
There have been no material changes to the Groups internal control over financial reporting during the year ended December 31, 
2023, that have materially affected, or are reasonably likely to materially affect, the Group’s internal control over financial reporting. 
36

===== SIDA 80 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
Control Framework 
Management assesses the effectiveness of the Corporation’s internal control over financial reporting using the Internal Control 
– Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission 
(COSO).   
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION 
This MD&A contains statements and information which constitute “forward-looking statements“ or “forward-looking information“ 
(within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements“) 
relate to future events, including the Corporation’s future performance, business prospects or opportunities. Actual results may differ 
materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this MD&A 
are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this MD&A, unless 
otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except 
as required by applicable laws. 
All statements other than statements of historical fact may be forward-looking statements. Any statements that express or involve 
discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, guidance, budgets, objectives, assumptions 
or future events or performance (often, but not always, using words or phrases such as “seek“, “anticipate“, “plan“, “continue“, 
“estimate“, “expect“, “may“, “will“, “project“, “forecast”, “predict“, “potential“, “targeting“, “intend“, “could“, “might“, “should“, 
“believe“, “budget“ and similar expressions) are not statements of historical fact and may be “forward-looking statements“. 
Forward-looking statements include, but are not limited to, statements with respect to: 
• 2024 production range, operating costs, operating cash flow, free cash flow, and capital and decommissioning expenditure 
estimates; 
• Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business 
plans and assumptions regarding the business environment, which are subject to change; 
• IPC’s financial and operational flexibility to continue to react to recent events and navigate the Corporation through periods of 
volatile commodity prices; 
• The ability to fully fund future expenditures from cash flows and current borrowing capacity; 
• IPC’s intention and ability to continue to implement its strategies to build long-term shareholder value; 
• The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth; 
• The continued facility uptime and reservoir performance in IPC’s areas of operation; 
• Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing, 
regulatory approvals, third party commercial arrangements, breakeven oil prices and net present values;
• Future development potential of the Suffield, Brooks, Ferguson and Mooney operations, including the timing and success of 
future oil and gas drilling and optimization programs; 
• Current and future operations and production performance at Onion Lake Thermal;
• The potential improvement in the Canadian oil egress situation and IPC’s ability to benefit from any such improvements;
• The ability of IPC to achieve and maintain current and forecast production in France and Malaysia; 
• The intention and ability of IPC to acquire further common shares under the NCIB, including the timing of any such purchases;
• The return of value to IPC’s shareholders as a result of the NCIB;
• The ability of IPC to implement further shareholder distributions in addition to the NCIB;
• IPC’s ability to implement its GHG emissions intensity and climate strategies and to achieve its net GHG emissions intensity 
reduction targets;
• Estimates of reserves and contingent resources; 
• The ability to generate free cash flows and use that cash to repay debt;
• IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the 
Corporation;
• IPC’s ability to maintain operations, production and business in light of any future pandemics and the restrictions and 
disruptions related thereto, including risks related to production delays and interruptions, changes in laws and regulations and 
reliance on third party operators and infrastructure; 
• IPC’s ability to identify and complete future acquisitions; and
• Future drilling and other exploration and development activities.
Statements relating to “reserves“ and “contingent resources“ are also deemed to be forward-looking statements, as they involve 
the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the 
quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery 
of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of 
management. See also “Reserves and Resources Advisory“.
The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations 
and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; 
interest rates; future well production rates and reserve and contingent resource volumes; operating costs; the timing of receipt of 
regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results 
of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location 
and extent of future drilling operations; the successful completion of acquisitions and dispositions; the benefits of acquisitions; 
37

===== SIDA 81 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally; 
the availability and cost of financing, labour and services; and the ability to market crude oil, natural gas and natural gas liquids 
successfully.
Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are reasonable, 
undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they will prove to 
be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks 
and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks.
These include, but are not limited to: 
• General global economic, market and business conditions;
• The risks associated with the oil and gas industry in general such as operational risks in development, exploration and 
production;
• Delays or changes in plans with respect to exploration or development projects or capital expenditures;
• The uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses;
• Health, safety and environmental risks;
• Commodity price fluctuations;
• Interest rate and exchange rate fluctuations;
• Marketing and transportation;
• Loss of markets;
• Environmental and climate-related risks;
• Competition;
• Incorrect assessment of the value of acquisitions;
• Failure to complete or realize the anticipated benefits of acquisitions or dispositions;
• The ability to access sufficient capital from internal and external sources;
• Failure to obtain required regulatory and other approvals; and
• Changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations. 
Readers are cautioned that the foregoing list of factors is not exhaustive. See also “Risk and Uncertainties”
Estimated FCF generation is based on IPC’s current business plans over the periods of 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 current business plans and assumptions, and the business 
environment, are subject to change. Actual results may differ materially from forward-looking estimates and forecasts.
Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in 
the Financial Statements, the Corporation’s material change report (MCR) dated February 6, 2024, the Corporation’s Annual 
Information Form (AIF) for the year ended December 31, 2022, (See “Cautionary Statement Regarding Forward-Looking 
Information”, “Reserves and Resources Advisory” and “Risk Factors”) and other reports on file with applicable securities 
regulatory authorities, including previous financial reports, management’s discussion and analysis and material change reports, 
which may be accessed through the SEDAR+ website (www.sedarplus.ca) or IPC’s website (www.international-petroleum.com).
Management of IPC approved the production, operating costs, operating cash flow, capital and decommissioning expenditures 
and free cash flow guidance and estimates contained herein as of the date of this MD&A release. The purpose of these guidance 
and estimates is to assist readers in understanding IPC’s expected and targeted financial results, and this information may not be 
appropriate for other purposes.
RESERVES AND RESOURCES ADVISORY 
This MD&A contains references to estimates of gross and net reserves and resources attributed to the Corporation’s oil and gas 
assets. Gross reserves/resources are the working interest (operating or non-operating) share before deduction of royalties and 
without including any royalty interests. Net reserves/resources are the working interest (operating or non-operating) share after 
deduction of royalty obligations, plus royalty interests in reserves/resources, and in respect of PSCs in Malaysia, adjusted for cost 
and profit oil. Unless otherwise indicated, reserves/resource volumes are presented on a gross basis.
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in 
Canada are effective as of December 31, 2023, and are included in the reports prepared by Sproule Associates Limited (Sproule), 
an independent qualified reserves evaluator, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and 
Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule’s December 
31, 2023 price forecasts. 
Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in 
France and Malaysia are effective as of December 31, 2023, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), 
an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 
31, 2023 price forecasts. 
38

===== SIDA 82 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
The price forecasts used in the Sproule and ERCE reports, are available on the website of Sproule (sproule. com) and are 
contained in the MCR. These price forecasts are as at December 31, 2023 and may not be reflective of current and future forecast 
commodity prices.
The reserve life index (RLI) is calculated by dividing the 2P reserves of 468 MMboe as at December 31, 2023, by the mid-point of 
the 2024 CMD production guidance of 46,000 to 48,000 boepd.
The product types comprising the 2P reserves described in this MD&A are contained in the MCR. See also “Supplemental 
Information regarding Product Types” below. Light, medium and heavy crude oil reserves/resources disclosed in this MD&A 
include solution gas and other by-products.
“2P reserves“ means proved plus probable reserves. “Proved reserves“ are those reserves that can be estimated with a high 
degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved 
reserves. “Probable reserves“ are those additional reserves that are less certain to be recovered than proved reserves. It is equally 
likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable 
reserves. 
Each of the reserves categories reported (proved and probable) may be divided into developed and undeveloped categories.  
“Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if 
facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) 
to put the reserves on production. The developed category may be subdivided into producing and non-producing. “Developed 
producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the 
estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date 
of resumption of production must be known with reasonable certainty. “Developed non-producing reserves” are those reserves 
that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption 
of production is unknown. “Undeveloped reserves” are those reserves expected to be recovered from known accumulations 
where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of 
production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known 
accumulations using established technology or technology under development, but which are not currently considered to be 
commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion 
of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be 
resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political, 
and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered 
recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in 
accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or 
characterized by their economic status.
There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a 
classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity 
that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best 
estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will 
equal or exceed the best estimate.
Contingent resources are further classified based on project maturity. The project maturity subclasses include development 
pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources 
are classified as either development on hold or development unclarified. Development on hold is defined as a contingent 
resource where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved 
that are usually beyond the control of the operator. Development unclarified is defined as a contingent resource that requires 
further appraisal to clarify the potential for development and has been assigned a lower chance of development until commercial 
considerations  can be clearly defined. Chance of development is the probability of a project being commercially viable. 
References to “unrisked“ contingent resources volumes means that the reported volumes of contingent resources have not been 
risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook guidance  
for contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies 
required for the re-classification of the contingent resources as reserves being resolved. Therefore, unrisked reported volumes 
of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such 
resources.
The contingent resources reported in this MD&A are estimates only. The estimates are based upon a number of factors and 
assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and 
commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil 
and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks 
and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is 
uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this MD&A.
39

===== SIDA 83 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
2P reserves and contingent resources included in the reports prepared by Sproule and ERCE in respect of IPC’s oil and gas assets 
in Canada, France and Malaysia have been aggregated by IPC. Estimates of reserves, resources and future net revenue for 
individual properties may not reflect the same level of confidence as estimates of reserves, resources and future net revenue for 
all properties, due to aggregation. This MD&A contains estimates of the net present value of the future net revenue from IPC’s 
reserves and contingent resources. The estimated values of future net revenue disclosed in this MD&A do not represent fair 
market value. There is no assurance that the forecast prices and cost assumptions used in the reserve and resources evaluations 
will be attained and variances could be material.
The reserves and resources information and data provided in this MD&A present only a portion of the disclosure required 
under NI 51-101. All of the required information will be contained in the Corporation’s Annual Information Form for the year 
ended December 31, 2023, which will be filed on SEDAR+ (accessible at www.sedarplus.ca) on or before April 1, 2024. Further 
information with respect to IPC’s reserves, contingent resources and estimates of future net revenue is disclosed in the MCR 
available under IPC’s profile on www.sedarplus.ca and on IPC’s website at www.international-petroleum.com.
References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.  
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel 
(bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value 
equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and 
crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an 
indication of value.
Supplemental Information regarding Product Types
The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily 
production figures provided in this document:
Heavy Crude Oil 
(Mbopd)
Light and Medium 
Crude Oil (Mbopd)
Conventional Natural Gas
(per day)
Total
(Mboepd)
Three months ended
December 31, 2023 25.7 6.6 103.8 MMcf                     
(17.3 Mboe) 49.6
December 31, 2022 22.6 10.3 98.1 MMcf                     
(16.4 Mboe) 49.2
Year ended December 31, 2023
December 31, 2023 25.8 8.1 102.8MMcf                     
(17.1 Mboe) 51.1
December 31, 2022 22.6 9.6 98.1MMcf                     
(16.4 Mboe) 48.6
This document also makes reference to IPC’s forecast average daily production of 46,000 to 48,000 boepd for 2024. IPC 
estimates that approximately 51% of that production will be comprised of heavy oil, approximately 15% will be comprised of light 
and medium crude oil and approximately 34% will be comprised of conventional natural gas.
40

===== SIDA 84 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
OTHER SUPPLEMENTARY INFORMATION
Abbreviations
CAD  Canadian dollar
MCAD  Million Canadian dollar
EUR  Euro
USD  US dollar
MUSD  Million US dollar
MYR  Malaysian Ringgit
FPSO  Floating Production Storage and Offloading (facility)
Oil related terms and measurements
AECO   The daily average benchmark price for natural gas at the AECO hub in southeast Alberta                                                                            
AESO  Alberta Electric System Operator
API   An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale
ASP   Alkaline surfactant polymer (an EOR process)
ARV  Argus WCS Houston (a reference price for the cost of transporting WCS quality oil from Alberta to Houston)
bbl   Barrel (1 barrel = 159 litres)
boe1   Barrels of oil equivalents
boepd   Barrels of oil equivalents per day
bopd   Barrels of oil per day
Bcf  Billion cubic feet
Bscf   Billion standard cubic feet 
C5  Condensate
CO2e  Carbon dioxide equivalents, including carbon dioxide, methane and nitrous oxide
Empress   The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border
EOR   Enhanced Oil Recovery
GJ  Gigajoules
Mbbl   Thousand barrels
MMbbl   Million barrels
Mboe   Thousand barrels of oil equivalents 
Mboepd   Thousand barrels of oil equivalents per day
Mbopd   Thousand barrels of oil per day
MMboe   Million barrels of oil equivalents
MMbtu   Million British thermal units
Mcf   Thousand cubic feet
Mcfpd  Thousand cubic feet per day
MMcf   Million cubic feet
MW  Mega watt
MWh  Mega watt per hour
NGL   Natural gas liquid
SAGD   Steam assisted gravity drainage (a thermal recovery process)
WTI   West Texas Intermediate (a light oil reference price)
WCS   Western Canadian Select (a heavy oil reference price)
1  All volume references to boe are calculated on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) 
unless otherwise indicated. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and 
does not represent a value equivalency at the wellhead. BOEs may be misleading, particularly if used in isolation. Given that the value ratio based 
on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 
6:1 basis may be misleading as an indication of value.
41

===== SIDA 85 =====

Management’s Discussion and Analysis
For the three months ended and year ended December 31, 2023
DIRECTORS
C. Ashley Heppenstall
Director, Chair
London, England
William Lundin
Director, President and Chief Executive Officer
Coppet, Switzerland
Chris Bruijnzeels
Director
Abcoude, The Netherlands
Donald K. Charter
Director
Toronto, Ontario, Canada
Lukas (Harry) H. Lundin
Director
Toronto, Ontario, Canada
Emily Moore
Director
Toronto, Ontario, Canada
Mike Nicholson
Director
Monaco
Deborah Starkman
Director
Toronto, Ontario, Canada
OFFICERS
Christophe Nerguararian
Chief Financial Officer
Geneva, Switzerland
Nicki Duncan
Chief Operating Officer
Geneva, Switzerland
Jeffrey Fountain
General Counsel and Corporate Secretary
Geneva, Switzerland
Rebecca Gordon
Senior Vice President Corporate Planning and 
Investor Relations
Geneva, Switzerland 
Chris Hogue
Senior Vice President, Canada
Calgary, Alberta, Canada
Ryan Adair
Vice President Asset Management and
Corporate Planning, Canada
Calgary, Alberta, Canada
Curtis White
Vice President Commercial, Canada
Calgary, Alberta, Canada
MEDIA AND INVESTOR RELATIONS
Robert Eriksson 
Stockholm, Sweden
CORPORATE OFFICE
Suite 2000 – 885 West Georgia Street 
Vancouver, British Columbia
V6C 3E8 Canada
Telephone: +1 604 689 7842
Website: www.international-petroleum.com
OPERATIONS OFFICE
5 Chemin de la Pallanterie
1222 Vésenaz
Switzerland
Telephone: +41 22 595 10 50
E-mail: info@international-petroleum.com
REGISTERED AND RECORDS OFFICE
Suite 3500 - 1133 Melville Street 
Vancouver, British Columbia
V6E 4E5 Canada
INDEPENDENT AUDITORS
PricewaterhouseCoopers SA, Switzerland
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta, and Toronto, Ontario
STOCK EXCHANGE LISTINGS
Toronto Stock Exchange and NASDAQ Stockholm 
Trading Symbol: IPCO
42

===== SIDA 86 =====

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□