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NC00249 p01 02.22 Operations & Financial Update Year End 2024 William Lundin, CEO Christophe Nerguararian, CFO February 11, 2025 Q 24 4
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NC00380 p07 01.25See Notes and Reader Advisory International Petroleum Corp. 2024 Highlights Record Investment Year MUSD MUSD 351 442 Blackrod Phase1 FY2024 Production Mboepd47.4 Mboepd47.4Q4 FY2024 Stable Operating Costs Q4 FY2024 18.2 USD/boe 17.0 USD/boe Strong Cash Flow 342 MUSD OCF MUSD FCF(135) FY2024 FY2024 Robust Balance Sheet Gross Cash 247 Net Debt 209 MUSD MUSD Sustainability Focus Carbon reduction & offsets material incidents No Share Repurchase 2023/24 NCIB 2024/25 NCIB completed million shares completed8.3 ~30% 2
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NC00380 p10 01.25 See Notes and Reader Advisory International Petroleum Corp. 2024 Production 20242023 Oil Brent Oil WCS Gas Production (Mboepd) Guidance range 48 46 Low High 51 48 50 2024 full year and Q4 average net production of 47.4 Mboepd International, 13% Canada Gas, 34% Canada Crude, 53% 2024 Production W CS Gas Brent 47.4 2022 46 42 2019 2020 46 50 46 49 2021 41 43 37 40 46 48 Above mid-point of full year production guidance range 3
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Q3 Capex guidance Capital adjustment Full year Capex 437 MUSD 5 MUSD 442 MUSD Full year capital expenditure of 442 MUSD 2024 Operating Costs See Notes and Reader Advisory NC00380 p03 01.25 International Petroleum Corp. 2024 Operating and Capital Expenditure Full year operating costs within guidance at 17.0 USD/boe Guidance <18 USD/boe Operating costs of 18.2 USD/boe in Q4 4
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NC00380 p04 01.25See Notes and Reader Advisory International Petroleum Corp. 2024 Operating Cash Flow 342 MUSD 81 USD/bbl (5/15) 257 MUSD 70 USD/bbl (5/15) 376 MUSD 90 USD/bbl (5/15) 335 MUSD 70 USD/bbl (5/15) 342 MUSD 80 USD/bbl (5/15) 78 MUSD 75 USD/bbl (4/13) 2024 OCF Q4 2024 CMD guidance OCF 2024 Guidance OCF Revised 2024 OCF guidance (Q3 2024) 5
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NC00380 p05 01.25 See Notes and Reader Advisory International Petroleum Corp. 2024 Free Cash Flow (excluding Blackrod) (including Blackrod) (excluding Blackrod) (including Blackrod) 2024 CMD Guidance FCF 2024 Forecast FCF 268 MUSD 2024 FCF 90 USD/bbl (5/15) 144 MUSD 70 USD/bbl (5/15) 229 MUSD 80 USD/bbl (5/15) 222 MUSD 70 USD/bbl (5/15) (133) MUSD 80 USD/bbl (5/15) (140) MUSD 70 USD/bbl (5/15) (94) MUSD 90 USD/bbl (5/15) (218) MUSD 70 USD/bbl (5/15) 216 MUSD (excluding Blackrod Phase 1) 81 USD/bbl (5/15) (135) MUSD (including Blackrod Phase 1) 81 USD/bbl (5/15) Revised 2024 guidance (Q3 2024) 6
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NC00380 p06 01.25 International Petroleum Corp. Share Repurchase See Notes and Reader Advisory Shares Outstanding at Spin off April 2017 Shares Outstanding @ January 31, 2025 SIB 2017 NCIB 2019/2020 NCIB 2021/2022 NCIB 2022/2023 NCIB 2023/2024 NCIB 2024/2025 SIB 2022 113.5 Million IPC shares +75.8 -25.5 4% Dilution -8.4 -9.6 -8.3 -9.3 -8.3 -2.2 117.7 BlackPearl Acquisition December 2018 ~4.5x production >1 billion boe (CR) Added >2.5 BUSD Net Asset Value +23 years added to reserves life 17x 2P reserves 71.6 million IPC shares repurchased since inception at an average price of SEK 74 / CAD 9.8 per share Completed 2023/2024 NCIB share repurchase program in November 2024 Renewed the NCIB in December 2024 7
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NC00380 p07 01.25 International Petroleum Corp. Sustainability See Notes and Reader Advisory 59 40 33 20 Canadian 28 IPC net emissions intensity 25 IPC target Canadian Industry average Scope 1 Net Emissions Intensity (kg CO2e/boe) 2019 2020 2021 2022 242023 2025 202028 Committed to a strong safety culture • No material safety incidents in 2024, achieved 35% decrease in the total recordable incident rate relative to 2023 Pursuing our climate strategy • On track to achieve 50% net emissions intensity reduction by 2025, extended to end 2028 Upholding our commitment to local communities • Prioritised local hiring in all regions of operations Health & Safety Climate Action Community Engagement 8
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Year End 2024 Financial Highlights 9
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Fourth Quarter 2024 Full Year 2024 Production (boepd) 47,400 47,400 Average Dated Brent Oil Price (USD/bbl) 74.7 80.7 Operating costs (USD/boe) 18.2 17.0 Operating cash flow (MUSD) 78.2 342.0 EBITDA (MUSD) 76.2 335.5 Capital Expenditure (MUSD) 129.0 442.4 Free cash flow (MUSD) -61.5 -135.5 Net result (MUSD) 0.4 102.2 See Notes and Reader Advisory Net Debt (MUSD) 208.5 10 Year End 2024 Financial Highlights
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Malaysia liftings: Q1 - 2024 - 1 cargo => February Q2 - 2024 - 2 cargoes => April & June Q3 - 2024 - 1 cargo => September Q4 - 2024 - 2 cargoes => November & December France: Q4 - 2024 - 1 Aquitaine lifting 2024 2023 USD/bbl Full Year Q4 Q3 Q2 Q1 Full Year Q4 Brent 80.7 74.7 80.1 85.0 83.2 82.6 84.3 Malaysia 86.1 (+5.4) 78.2 (+3.5) 80.9 (+0.8) 93.3 (+8.3) 91.6 (+8.4) 91.0 (+8.4) 85.2 (+0.9) France 80.0 (-0.7) 74.1 (-0.6) 80.5 (+0.4) 85.0 (–) 82.9 (-0.3) 81.9 (-0.7) 82.0 (-2.3) WTI 75.7 70.3 75.0 80.6 76.9 77.7 78.6 WCS (calculated) 60.9 57.7 61.5 67.0 57.5 59.1 57.0 Suffield 60.9 (–) 56.8 (-0.9) 61.7 (+0.2) 67.1 (+0.1) 57.8 (+0.3) 58.3 (-0.8) 56.6 (-0.4) Onion Lake 60.7 (-0.2) 57.0 (-0.7) 61.9 (+0.4) 66.8 (-0.2) 57.5 (–) 58.7 (-0.4) 55.9 (-1.1) 11 Year End 2024 Realised Oil Prices
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1 2 3 4 5 6 7 8 9 10 1 0 2 3 4 5 6 7 8 9 10 CAD/Mcf USD/MMbtu May Jun Jul Aug Sep Oct Nov Dec 2021 Jan Feb Mar Apr Jan Feb Mar AprMay Jun Jul Aug Sep Oct Nov Dec Aug Sep Oct Aug Sep OctNov Dec 2022 2023 2024 Jan Feb Mar Apr May Jun Apr May JunJul JulJan Feb Nov Dec Jan FebMar 0 Empress / AECO differential (1) 3.36 CAD/Mcf including hedge AECO Day Ahead Index Realised Price CAD/MMcf Henry Hub Price USD/MMbtu AECO Empress Realised (to AECO) 2023 2.29 2.30 2.33 (+0.04) Q4 2.61 2.61 2.73 (1) (+0.12) Full Year 2.49 2.59 2.52 (+0.03) 2024 Q1 1.17 1.17 1.17 (–) Q2Q3 1.44 1.49 1.51 (+0.07) 0.67 0.68 0.72 (+0.05) Q4 1.44 1.49 1.61 (+0.17) Full YearCAD/mcf 3.11 3.05 3.72 4.87 4.96 5.75 5.88 3.60 2.44 2.62 2.33 2.52 1.17 7.81 1.57 0.72 1.61 6.26 4.10 NC00368 p01 Hedge CAD/Mcf (14.5 MMcfd) Hedge CAD/Mcf (33.7 MMcfd) 12 Year End 2024 Realised Gas Prices
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NC00380 fin p01 01.25 Million USD Million USD 100 200 300 0 100 50 50 200 300 150 250 350 150 250 350 400400 0 2024 2024 350 Q2 85 Q3 123 Q4 66 2023 2023 EBITDAOperating Cash Flow 342 Q2 102 Q3 73 Q4 78 Q1 89 353 Q2 84 Q3 119 Q4 74 Q1 76 335 Q2 104 Q3 68 Q4 76 Q1 76 Q1 87 See Notes and Reader Advisory 13 Year End 2024 Financial Results – Operating Cash Flow & EBITDA
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NC00380 fin p02 01.25 12 10 14 16 18 20 22 12 10 14 16 20 22 Q1 2024 Actual Q2 2024 Actual Q3 2024 Actual Q4 2024 Actual USD/boe USD/boeQuarterly operating costs 2024 Operating Costs Revised Guidance: <18.0 USD/boe 2024 Operating Costs 17.0 USD/boe See Notes and Reader Advisory 14 Year End 2024 Operating Costs
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Fourth Quarter 2024 Full Year 2024 Average Dated Brent oil price (74.7 USD/bbl) (80.7 USD/bbl) Revenue 45.7 46.0 Cost of operations -15.6 -14.5 Tariff and transportation -2.4 -2.2 Production taxes -0.2 -0.3 Operating costs -18.2 -17.0 Cost of blending -8.3 -8.8 Inventory movements -1.1 -0.1 Revenue – production costs 18.2 20.2 Cash taxes -0.3 -0.5 Operating cash flow 17.9 19.7 General and administration costs -0.8 -0.9 EBITDA 17.4 19.3 See Notes and Reader Advisory 15 Year End 2024 Netback (USD/boe)
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50 (50) (150) 150 100 0 0 (100) (250) (200) 200 250 300 350 400 50 (50) (150) 150 100 (100) (250) (200) 200 250 300 350 450 450 400 MUSD MUSD Blackrod Phase 1 MUSD 351.3 Other MUSD 91.1 Operating Cash Flow MUSD 342.0 Net Cash Financial items MUSD -19.7 Development capex & abex MUSD -442.4Cash G&A MUSD -14.9 Share buyback MUSD -102.2 Opening Net Cash 1 Jan 2024 MUSD 58.0 Closing Net Debt 31 Dec 2024 MUSD -208.5 Change in working capital & other MUSD -29.3 NC00368 p02 See Notes and Reader Advisory 16 Year End 2024 Net Cash/Debt (MUSD)
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MUSD Fourth Quarter 2024 Full Year 2024 Net interest expense 5.9 18.2 Amortisation of capitalised financing fees 0.6 2.1 Unwinding of asset retirement obligation discount 3.7 14.6 Foreign exchange loss (gain), net and others 25.6 24.8 Net Financial Items 35.8 59.7 MUSD Fourth Quarter 2024 Full Year 2024 G&A 3.6 14.9 G&A – Depreciation 0.3 1.2 G&A Expense 3.9 16.1 See Notes and Reader Advisory 17 Year End 2024 G&A / Financial Items
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NC00380 fin p03 01.25 100 200 300 400 500 600 700 800 900 0 100 200 300 400 500 600 700 800 900 0 Million USD Million USD Revenue MUSD 797.8 47,400 boepd Depletion MUSD -137.3 Production costs MUSD -448.2 17.0 USD/boe Exploration and business development costs MUSD -2.1 G&A MUSD -16.1 Other Income MUSD 1.1 Tax MUSD -33.3 Financial items MUSD -59.7 Net result MUSD 102.2 Gross profit MUSD 210.2 Cash Margin MUSD 349.6 See Notes and Reader Advisory 18 Year End 2024 Financial Results
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MUSD 31 Dec 2024 31 Dec 2023 Assets Oil and gas assets 1,501.3 1,303.9 Other non-current assets 53.5 68.5 Current assets 152.3 173.5 Cash 246.6 517.1 1,953.7 2,063.0 Liabilities Financial liabilities 1.7 5.4 Bonds (net of capitalised fees) 439.9 435.0 Provisions 268.4 250.7 Other non-current liabilities 96.1 88.7 Current liabilities 208.1 202.9 Equity 939.5 1,080.3 1,953.7 2,063.0 19 31 December 2024 Balance Sheet
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NC00351 p12 02.24 Maturity May 2026 Undrawn and fully available MCAD 40 letters of credit issued including MCAD 35 for Blackrod pipeline construction agreements Bonds MUSD 450 Maturity February 2027 7.25% coupon Interest payable February 1 st and August 1st Canadian RCF MCAD 180 Letter of Credit Facility French loan MEUR 4.9 at December 31, 2024 Maturity May 2026 Repayments of MEUR 0.8 quarterly International Petroleum Corp. Capital Structure 20
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International Petroleum Corp. Hedging - 2024/2025 2024 Hedges 2025 Hedges Oil WTI Q1 2024: 6,250 bbl/d @ 81 USD/bbl Q2-Q4 2024: 12,250 bbl/d @ 80 USD/bbl Jan 2025: 7,000 bbl/d @ 71 USD/bbl Feb-Dec 2025: 10,000 bbl/d @ 71 USD/bbl Oil WTI-WCS differential 2024: 17,700 bbl/d @ -15 USD/bbl 2025: 11,700 bbl/d @ -14 USD/bbl Oil Brent Q2-Q4 2024: 3,000 bbl/d @ 85 USD/bbl Jan 2025: 1,000 bbl/d @ 75 USD/bbl Feb-Dec 2025: 2,000 bbl/d @ 76 USD/bbl Gas Aug-Dec 2024: 14,500 Mcf/d @ 1.57 CAD/Mcf 2025: 9,600 Mcf/d @ 2.6 CAD/Mcf FX Hedging 2024: Buy 20 MCAD/month @ 1.36 (sell USD) Buy 11.5 MMYR/month @ 4.63 (sell USD) May-Dec 2024: Buy 2.5 MEUR/month @ 1.07 (sell USD) 2024: Buy 406 MCAD @ 1.32 (sell USD) - Capex 2025: Buy 520 MCAD @ 1.36 (sell USD) 2025: Buy 27 MEUR @ 1.07 (sell USD) 2025: Buy 138 MMYR @ 4.40 (sell USD) 21
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NC00380 p07 01.25See Notes and Reader Advisory International Petroleum Corp. 2024 Highlights Record Investment Year MUSD MUSD 351 442 Blackrod Phase1 FY2024 Production Mboepd47.4 Mboepd47.4Q4 FY2024 Stable Operating Costs Q4 FY2024 18.2 USD/boe 17.0 USD/boe Strong Cash Flow 342 MUSD OCF MUSD FCF(135) FY2024 FY2024 Robust Balance Sheet Gross Cash 247 Net Debt 209 MUSD MUSD Sustainability Focus Carbon reduction & offsets material incidents No Share Repurchase 2023/24 NCIB 2024/25 NCIB completed million shares completed8.3 ~30% 22
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Notes Page 2: 2024 Highlights • For production figures, see Reader Advisory, including “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory” and the material change report dated February 11, 2025 (MCR) available on IPC’s website at www.international-petroleum.com and filed under IPC’s profile on SEDAR+ at www.sedarplus.ca. • Operating cash flow (OCF), free cash flow (FCF), earnings before interest, tax, depreciation and amortization (EBITDA), operating costs and net cash/net debt are “Non-IFRS Measures”. See Reader Advisory and the management’s discussion and analysis for the year ended December 31, 2024 (MD&A) available on IPC’s website at www.international-petroleum.com and filed under IPC’s profile on SEDAR+ at www.sedarplus.ca, including “Non-IFRS Measures”. • Capital expenditure of USD 442 million includes decommissioning expenditure of USD 8 million. Page 3: 2024 Production • For production figures, see Reader Advisory, including “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”. Page 4: 2024 Operating and Capital Expenditure • Operating costs is a “Non-IFRS Measure”. See Reader Advisory and MD&A. • Capital expenditure includes decommissioning expenditure of USD 8 million. Page 5: 2024 Operating Cash Flow • OCF is a “Non-IFRS Measure”. See Reader Advisory and MD&A. • Brent oil price assumptions with Brent to WTI and WTI to WCS assumptions in USD/bbl, in brackets. Page 6: 2024 Free Cash Flow • FCF is a “Non-IFRS Measure”. See Reader Advisory and MD&A. • Brent oil price assumptions with Brent to WTI and WTI to WCS assumptions in USD/bbl, in brackets. Page 7: Share Repurchase • For production figures, see Reader Advisory and MCR, including “Reserves and Resources Advisory”. • 2P reserves and contingent resources (best estimates, unrisked) are as at December 31, 2024. See Reader Advisory and MCR, including “Reserves and Resources Advisory”. • As at January 31, 2025, the number of IPC common shares was 117,680,075, being 117,781,927 common shares outstanding less 101,852 common shares held in treasury. • NPV is after tax, discounted at 10% and based upon the forecast prices and other assumptions further described in the MCR. NAV is calculated as NPV less net debt of USD 209 million as at December 31, 2024. Per share values assume 119.1 million common shares as at December 31, 2024 and exchange rates of 11.10 SEK/USD and 1.44 CAD/USD. Page 8: Sustainability • Net emissions intensity target is compared to IPC’s 2019 net emissions intensity baseline. • Emissions intensity is the ratio between oil and gas production and the associated carbon emissions, and net emissions intensity reflects gross emissions less operational emission reductions and carbon offsets. Page 10: Financial Highlights • Operating costs, OCF, EBITDA, FCF and net cash are “Non-IFRS Measures”. See Reader Advisory and MD&A. • Capital expenditure of USD 442 million includes decommissioning expenditure of USD 8 million. Page 13: Financial Results – Operating Cash Flow & EBITDA • OCF and EBITDA are “Non-IFRS Measures”. See Reader Advisory and MD&A. Page 14: Operating Costs • Operating costs is a “Non-IFRS Measure”. See Reader Advisory and MD&A. Page 15: Netback (USD/boe) • Netbacks are based on production volumes. • Operating costs, OCF and EBITDA are “Non-IFRS Measures”. See Reader Advisory and MD&A. • General and administration costs are net of depreciation. Page 16: Net Cash/Debt (MUSD) • OCF and net cash / net debt are “Non-IFRS Measures”. See Reader Advisory and MD&A. Page 17: G&A / Financial Items • Foreign exchange loss (gain), net and others are mainly non-cash, driven by the revaluation of external and group loans. Page 22: 2024 Highlights • See Notes to Page 2: “2024 Highlights” 23
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Reader Advisory Forward-Looking Statements This presentation 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 presentation are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this presentation, 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: • 2025 production ranges (including total daily average production), production composition, cash flows, operating costs and capital and decommissioning expenditure estimates; • Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business plans and assumptions regarding the business environment, which are subject to change; • IPC’s financial and operational flexibility to 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; • Current and future production performance, operations and development potential of the Onion Lake Thermal, Suffield, Brooks, Ferguson and Mooney operations, including the timing and success of future oil and gas drilling and optimization programs; • 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; • IPC’s ability to implement projects to reduce net emissions intensity, including potential carbon capture and storage; • Estimates of reserves and contingent resources; • The ability to generate free cash flows and use that cash to repay debt; • IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the Corporation; • IPC’s ability to identify and complete future acquisitions; • Expectations regarding the oil and gas industry in Canada, Malaysia and France, including assumptions regarding future royalty rates, regulatory approvals, legislative changes, and ongoing projects and their expected completion; and • Future drilling and other exploration and development activities. Statements relating to “reserves” and “contingent resources” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management. The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve and contingent resource volumes; operating costs; the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the benefits of acquisitions; the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally; the availability and cost of financing, labour and services; and the ability to market crude oil, natural gas and natural gas liquids successfully. Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: • general global economic, market and business conditions; • the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; • delays or changes in plans with respect to exploration or development projects or capital expenditures; • the uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses; • health, safety and environmental risks; • commodity price fluctuations; • interest rate and exchange rate fluctuations; • marketing and transportation; • loss of markets; • environmental and climate-related risks; • competition; • incorrect assessment of the value of acquisitions; • failure to complete or realize the anticipated benefits of acquisitions or dispositions; • the ability to access sufficient capital from internal and external sources; • failure to obtain required regulatory and other approvals; and • changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations. Readers are cautioned that the foregoing list of factors is not exhaustive. 24
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Reader Advisory Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the financial statements (Financial Statements) and the management’s discussion and analysis for the three months and year ended December 31, 2024 (MD&A) (See “Risks and Uncertainties”, “Cautionary Statement Regarding Forward-Looking Information” and “Reserves and Resources Advisory” therein), the Corporation’s material change report dated February 11, 2025 (MCR), the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2023 (See “Cautionary Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “ Risk Factors” therein) 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 presentation. 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. Estimated production and FCF generation are based on IPC’s current business plans over the periods of 2025 to 2029 and 2030 to 2034, less net debt of USD 209 million as at December 31, 2024, with assumptions based on the reports of IPC’s independent reserves evaluators, and including certain corporate adjustments relating to estimated general and administration costs and hedging, and excluding shareholder distributions and financing costs. Assumptions include average net production of approximately 57 Mboepd over the period of 2025 to 2029, average net production of approximately 63 Mboepd over the period of 2030 to 2034, average Brent oil prices of USD 75 to 95 per bbl 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. Non-IFRS Measures References are made in this presentation to “operating cash flow” (OCF), “free cash flow” (FCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA), “operating costs” and “net debt”/”net cash”, which are not generally accepted accounting measures under International Financial Reporting Standards (IFRS) and do not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with 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 the cash generated by and the financial performance and position 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 Corporation’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 Corporation’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 issuers. 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. The definition and reconciliation of each non-IFRS measure is presented in IPC’s MD&A (See “Non-IFRS Measures” therein). Reserves and Resources Advisory This presentation 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, 2024, 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, 2024 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, 2024, 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, 2024 price forecasts. The price forecasts used in the Sproule and ERCE reports are available on the website of Sproule (sproule.com) and are contained in the MCR. These price forecasts are as at December 31, 2024 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 493 MMboe as at December 31, 2024, by the mid-point of the 2025 production guidance of 43,000 to 45,000 boepd. The product types comprising the 2P reserves and contingent resources described in this presentation are contained in the MCR. See also “Supplemental Information regarding Product Types” below. Light, medium and heavy crude oil reserves/resources disclosed in this presentation 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. 25
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Reader Advisory 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 contingencies 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 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 presentation 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 presentation. References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”. 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 presentation 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 presentation 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. 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. The reserves and resources information and data provided in this presentation 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, 2024, which will be filed on SEDAR+ (accessible at www.sedarplus.ca) on or before April 1, 2025. Further information with respect to IPC’s reserves, contingent resources and estimates of future net revenue, including assumptions relating to the calculation of net present value and other relevant information related to the contingent resources disclosed, is disclosed in the MCR available under IPC’s profile on www.sedarplus.ca and on IPC’s website at www.international-petroleum.com. 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 (Mboepd) Light and Medium Crude Oil (Mboepd) Conventional Natural Gas (per day) Total (Mboepd) Three months ended December 31, 2024 24.3 7.1 95.9 MMcf (16.0 Mboe) 47.4 December 31, 2023 25.7 6.6 103.8 MMcf (17.3 Mboe) 49.6 Year ended December 31, 2024 23.9 7.7 95.1 MMcf (15.8 Mboe) 47.4 December 31, 2023 25.8 8.1 102.8 MMcf (17.1 Mboe) 51.1 This presentation also makes reference to IPC’s forecast total average daily production of 43,000 to 45,000 boepd for 2025. IPC estimates that approximately 55% of that production will be comprised of heavy oil, approximately 12% will be comprised of light and medium crude oil and approximately 33% will be comprised of conventional natural gas. 26
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Reader Advisory This presentation includes oil and gas metrics including “cash margin netback”, “taxation netback”, “operating cash flow netback”, “cash taxes”, “EBITDA netback” and “profit netback”. Such metrics do not have a standardized meaning under IFRS or otherwise, and as such may not be reliable. This information should not be used to make comparisons. • “Cash margin netback” is calculated on a per boe basis as oil and gas sales, less operating, tariff/transportation and production tax expenses. Netback is a common metric used in the oil and gas industry and is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. • “Taxation netback” is calculated on a per boe basis as current tax charge/credit less deferred tax charge/credit. Taxation netback is used to measure taxation on a per boe basis. • “Operating cash flow netback” is calculated as cash margin netback less cash taxes. Operating cash flow netback is used to measure operating results on a per boe basis of cash flow. • “Cash taxes” is calculated as taxes payable in cash, and not only for accounting purposes. Cash taxes is used to measure cash flow. • “EBITDA netback” is calculated as cash margin netback less general and administration expenses. EBITDA netback is used by management to measure operating results on a per boe basis. • “Profit netback” is calculated as cash margin netback less depletion/depreciation, general and administration expenses and financial items. Profit netback is used by management to measure operating results on a per boe basis. Currency All dollar amounts in this presentation are expressed in United States dollars, except where otherwise noted. References herein to USD mean United States dollars. References herein to CAD mean Canadian dollars. Oil related terms and measurements AECO The daily average benchmark price for natural gas at the AECO hub in southeast Alberta AESO Alberta Electric System Operator API An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale Alkaline surfactant polymer (an EOR process) ARV Argus WCS Houston (a reference price for the cost of transporting WCS quality oil from Alberta to Houston) bbl Barrel (1 barrel = 159 litres) boe Barrels of oil equivalents boepd Barrels of oil equivalents per day bopd Barrels of oil per day Bcf Billion 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 T exas Intermediate (a light oil reference price) WCS Western Canadian Select (a heavy oil reference price) 27
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