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NC00249 p01 02.22 Operations & Financial Update Year End 2025 William Lundin, CEO Christophe Nerguararian, CFO February 10, 2026 Q 25 4
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~30% NC00408 p07 01.26 International Petroleum Corp. Q4 and Full Year 2025 Highlights See Notes and Reader Advisory Organic Growth Oil Hedging Production Guidance Blackrod Phase 1 schedule advancement, first steam achieved at year end 2025 and first oil expected in Q3 2026 2025 capital expenditure of 344 MUSD, in line with guidance of 340 MUSD Blackrod Phase 1 growth capex of 228 MUSD in 2025, cumulative spend since 2023 of 820 MUSD 2025: 11,700 bopd WTI-WCS at -14 USD/bbl (Jul-Dec) 10,000 bopd WTI @ 71 USD/bbl (Feb-Dec) 4,000 bopd WTI Collar @ 65–75 USD/bbl (Jul-Dec) 2,000 bopd dated Brent @ 76 USD/bbl (Feb-Dec) Share Repurchase 2024/2025 Normal Course Issuer Bid (NCIB) program completed with 7.7 million shares repurchased and cancelled ESG No material safety incidents Annual Sustainability Report issued in Q3 2025 450 MUSD of Bonds refinanced in October 2025 with new maturity date of October 2030 Canadian Revolving Credit Facility (RCF) of 250 MCAD Net debt of 484 MUSD as at year end Quarterly average net production 45,600 boepd 2025 average net production of 44,900 boepd, at high end of guidance range 43,000 – 45,000 boepd Cash Flow Q4 Operating Cash Flow (OCF) 63 MUSD and full year OCF of 259 MUSD, ahead of guidance Q4 Free Cash Flow (FCF) of (29) MUSD and full year FCF of (153) MUSD, ahead of guidance Liquidity Q4 operating costs of 18.4 USD/boe 2025 operating costs of 17.8 USD/boe, below low end of guidance range 18-19 USD/boe Operating costs 2
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NC00408 p10 01.26 See Notes and Reader Advisory International Petroleum Corp. 2025 Production and Operating Expenditure NC00402 p03 10.25 2025 average net production of 44.9 Mboepd near high end of CMD production guidance range 2025 operating expenditure of 17.8 USD/boe Below low end of guidance 45 43 44.9 2024 20252023 Oil Brent Oil WCS Gas Production (Mboepd) Guidance range 48 46 Low High 51 48 50 47.4 2022 46 42 2019 2020 46 50 46 49 2021 41 43 37 40 46 48 2025 Operating Costs 3
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NC00408 p04 01.26 International Petroleum Corp. 2025 Operating Cash Flow See Notes and Reader Advisory (1) Brent oil price with Brent to WTI differential and WTI to WCS differential in brackets in USD/bbl 210 MUSD 65 USD/bbl (5/15)(1) 280 MUSD 85 USD/bbl (5/15)(1) 245 MUSD 55 USD/bbl (3/10)(1) 255 MUSD 65 USD/bbl (3/10)(1) 63 MUSD 64 USD/bbl (5/11)(1) 259 MUSD 69 USD/bbl (4/11)(1) 2025 OCF 2025 CMD guidance OCF 2025 Forecast OCF Q4 4
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NC00408 p03 01.26 International Petroleum Corp. 2025 Capital Expenditure NC00408 p3 10.25See Notes and Reader Advisory Canada 296 MUSD France 6 MUSD Malaysia 42 MUSD • FAB development preparations • Optimization • Blackrod Phase 1 • Blackrod resource maturation • OLT infill drilling • Other projects • Bertam infill drilling •Well workover Final major growth spend year for Blackrod Phase 1 development complete Blackrod Phase 1 Blackrod Other Non-Blackrod Decommissioning 228 MUSD 26 MUSD 83 MUSD 7 MUSD 2025 annual capital expenditure of 344 MUSD 2025 CAPEX 344 MUSD 5
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NC00408 p05 01.26 International Petroleum Corp. 2025 Free Cash Flow See Notes and Reader Advisory (excluding Blackrod) (including Blackrod) (excluding Blackrod) (including Blackrod) 2025 CMD FCF Guidance 2025 Forecast FCF 150 MUSD 2025 FCF 85 USD/bbl (5/15)(1) 80 MUSD 65 USD/bbl (5/15)(1) 90 MUSD 65 USD/bbl (3/10)(1) 80 MUSD 55 USD/bbl (3/10)(1) (160) MUSD 65 USD/bbl (3/10)(1) (170) MUSD 55 USD/bbl (3/10)(1) (80) MUSD 85 USD/bbl (5/15)(1) (150) MUSD 65 USD/bbl (5/15)(1) 103 MUSD (excluding Blackrod) 69 USD/bbl (4/11)(1) (153) MUSD (including Blackrod) 69 USD/bbl (4/11)(1) (1) Brent oil price with Brent to WTI differential and WTI to WCS differential in brackets in USD/bbl 6
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NC00408 p06 01.26 International Petroleum Corp. Share Repurchase See Notes and Reader Advisory Shares Outstanding at Spin off April 2017 Shares Outstanding @ January 31, 2026 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 No Dilution -8.4 -9.6 -8.3 -9.3 -8.3 -7.7 112.2 BlackPearl Acquisition December 2018 ~4.5x production >1 billion boe (CR) 4x Net Asset Value +23 years added to reserves life 18x 2P reserves 77 million IPC shares repurchased since inception at an average price of SEK 79 / CAD 11 per share Normal Course Issuer Bid (NCIB) 2024/2025 completed 7
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Year End 2025 Financial Highlights 8
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Fourth Quarter 2025 Full Year 2025 Production (boepd) 45,600 44,900 Average Dated Brent Oil Price (USD/bbl) 63.7 69.1 Operating costs (USD/boe) 18.4 17.8 Operating cash flow (MUSD) 63.1 258.9 EBITDA (MUSD) 59.0 243.5 Capital Expenditure (MUSD) 63 344 Free cash flow (MUSD) -28.6 -153.1 Net result (MUSD) -5.0 28.9 See Notes and Reader Advisory Net debt (MUSD) 483.6 9 Year End 2025 Financial Highlights
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Malaysia liftings: Q1 - 2025 - 1 cargo => March Q2 - 2025 - 1 cargo => May Q3 - 2025 - 1 cargo => August Q4 - 2025 - 2 cargos => October & December 2025 2024 2024 2023 USD/bbl Full Year Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Full Year Full Year Brent 69.1 63.7 69.1 67.9 75.7 74.7 80.1 85.0 83.2 80.7 82.6 Malaysia 71.5 (+2.4) 67.7 (+4.0) 74.5 (+5.4) 67.3 (-0.6) 78.8 (+3.1) 78.2 (+3.5) 80.9 (+0.8) 93.3 (+8.3) 91.6 (+8.4) 86.1 (+5.4) 91.0 (+8.4) France 69.6 (+0.5) 64.1 (+0.4) 69.5 (+0.4) 68.5 (+0.6) 75.8 (+0.1) 74.1 (-0.6) 80.5 (+0.4) 85.0 (–) 82.9 (-0.3) 80.0 (-0.7) 81.9 (-0.7) WTI 64.8 59.2 65.0 63.8 71.5 70.3 75.0 80.6 76.9 75.7 77.7 WCS (calculated) 53.7 (-11.1) 48.0 (-11.2) 54.6 (-10.4) 53.6 (-10.2) 58.8 (-12.7) 57.7 (-12.6) 61.5 (-13.5) 67.0 (-13.6) 57.5 (-19.4) 60.9 (-14.8) 59.1 (-18.6) Suffield 53.1 (-0.6) 47.3 (-0.7) 54.4 (-0.2) 52.7 (-0.9) 57.8 (-1.0) 56.8 (-0.9) 61.7 (+0.2) 67.1 (+0.1) 57.8 (+0.3) 60.9 (–) 58.3 (-0.8) Onion Lake 53.3 (-0.4) 47.6 (-0.4) 54.1 (-0.5) 53.4 (-0.2) 58.3 (-0.5) 57.0 (-0.7) 61.9 (+0.4) 66.8 (-0.2) 57.5 (–) 60.7 (-0.2) 58.7 (-0.4) 10 Year End 2025 Realised Oil Prices
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1 -1 0 2 3 4 5 6 7 8 1 -1 0 2 3 4 5 6 7 8 CAD/Mcf USD/Mbtu JanJan Feb Mar AprMay Jun Jul Aug Sep Oct Nov Dec Aug Sep Oct Nov Sep Oct NovDec Dec 2023 2024 2025 Jan Feb Mar Apr May Jun Apr May JunJul Aug JulJan Feb Mar NC00410 p01 Empress / AECO differential AECO Day Ahead Index Realised Price CAD/Mcf Henry Hub Price USD/Mbtu AECO Empress Realised (to AECO) 2024 1.44 1.49 1.51 (+0.07) Full Year 20252025 2.13 2.43 2.40 (+0.27) Q1 1.65 1.96 1.82 (+0.17) Q2 0.62 0.62 0.84 (+0.22) Q3 2.16 2.38 2.46 (+0.30) Q4 1.63 1.84 1.87 (+0.24) Full Year 2.49 2.59 2.52 (+0.03) 2024 Q1 1.17 1.17 1.17 (–) Q2Q3 0.67 0.68 0.72 (+0.05) Q4 1.44 1.49 1.61 (+0.17) CAD/Mcf 3.60 2.44 2.62 2.33 2.52 1.17 0.72 1.61 2.40 1.82 0.84 2.46 11 Year End 2025 Realised Gas Prices
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NC00402 fin p01 10.25 100 150 50 200 250 300 0 100 150 50 200 250 350 350 300 0 EBITDAOperating Cash Flow Million USD Million USD 2025 2025 335 2024 2024 259 Q2 102 Q3 73 Q3 78 Q1 89 342 244 Q2 104 Q3 68 Q4 76 Q1 87Q1 75 Q2 55 Q3 66 Q4 63 Q1 71 Q2 52 Q3 62 Q4 59 See Notes and Reader Advisory 12 Year End 2025 Financial Results – Operating Cash Flow & EBITDA
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NC00402 fin p02 10.25 Q1 2025 Actual Q2 2025 Actual Q3 2025 Actual Q4 2025 Actual USD/boe USD/boeQuarterly operating costs 2025 Operating Costs Guidance: 18–19 USD/boe 2025 Operating Costs 17.8 USD/boe 12 10 14 16 18 20 22 12 10 14 16 20 22 See Notes and Reader Advisory 13 Year End 2025 Operating Costs
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Fourth Quarter 2025 Full Year 2025 Average Dated Brent oil price (63.7 USD/bbl) (69.1 USD/bbl) Revenue 42.0 41.9 Cost of operations -15.8 -15.2 Tariff and transportation -2.3 -2.4 Production taxes -0.3 -0.3 Operating costs -18.4 -17.9 Cost of blending -7.4 -8.2 Inventory movements -1.4 – Revenue – production costs 14.8 15.8 Cash taxes 0.2 – Operating cash flow 15.0 15.8 General and administration costs -0.8 -0.9 EBITDA 14.0 14.9 See Notes and Reader Advisory 14 Year End 2025 Netback (USD/boe)
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(50) 50 50 (150) 0 (100) (250) (200) (350) (300) (450) (400) (500) (500) (50) (150) 0 (100) (250) (200) (350) (300) (450) (400) MUSD MUSD Operating Cash Flow MUSD 258.9 Net Cash Financial items MUSD -59.6 Development capex & abex MUSD -344.2 Cash G&A MUSD -15.4 Share buyback MUSD -100.3 Opening Net Debt 1 Jan 2025 MUSD -208.5 Closing Net Debt 31 Dec 2025 MUSD -483.6 Change in working capital & other MUSD -14.5 Blackrod Phase 1 MUSD -228.4 Other MUSD -115.8 NC00410 p02See Notes and Reader Advisory 15 Year End 2025 Net Cash/Debt (MUSD)
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MUSD Fourth Quarter 2025 Full Year 2025 Net interest expense 13.5 38.6 Amortisation of capitalised financing fees 2.8 4.3 Unwinding of asset retirement obligation discount 4.2 16.5 Foreign exchange loss (gain), net and others 5.6 6.4 Net Financial Items -26.1 -65.8 MUSD Fourth Quarter 2025 Full Year 2025 G&A 3.4 15.4 G&A – Depreciation 0.4 1.4 G&A Expense 3.8 16.8 See Notes and Reader Advisory 16 Year End 2025 G&A / Financial Items
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NC00402 fin p03 10.25 200 400 450 500 700 600 650 550 300 100 250 350 150 50 200 400 450 500 700 600 650 550 300 100 250 350 150 50 0 0 Million USD Million USD Revenue MUSD 685.9 44,900 boepd Depletion MUSD -128.4 Production costs MUSD -427.6 17.8 USD/boe G&A MUSD -16.8 Tax MUSD -17.4 Other income/(expense) MUSD 0.8 Financial items MUSD -65.8 Exploration and Business Development costs MUSD -1.8 Net result MUSD 28.9 Gross profit MUSD 128.1 Cash Margin MUSD 258.3 See Notes and Reader Advisory 17 Year End 2025 Financial Results
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MUSD 31 Dec 2025 31 Dec 2024 Assets Oil and gas assets 1,795.1 1,501.3 Other non-current assets 52.2 53.5 Current assets 123.3 152.3 Cash 7.0 246.6 1,977.6 1,953.7 Liabilities Financial liabilities 38.7 1.7 Bonds (net of capitalised fees) 442.3 439.9 Provisions 284.2 268.4 Other non-current liabilities 125.0 96.1 Current liabilities 160.2 208.1 Equity 927.2 939.5 1,977.6 1,953.7 18 31 December 2025 Balance Sheet
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International Petroleum Corp. Capital Structure See Notes and Reader Advisory NC00415 p12 01.26 Maturity May 2027 Drawdown at December 31, 2025: MCAD 53 MCAD 19.7 letters of credit issued as at December 31, 2025 Bonds MUSD 450 Refinanced in Q4 2025 Maturity October 2030 7.50% coupon, MUSD 25 semi-annual amortization starting April 2028 Canadian RCF MCAD 250 Letter of Credit Facility French loan MEUR 1.7 at December 31, 2025 Maturity May 2026 Repayments of MEUR 0.8 quarterly 19
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International Petroleum Corp. Hedging - 2025 2025 Hedges Executed Oil WTI 2025 Jan: 7,000 bbl/d @ 70.57 USD/bbl 2025 Feb-Dec: 10,000 bbl/d @ 71.30 USD/bbl Oil WTI Collar 2025 Jul-Dec: 4,000 bbl/d @ 65.00–75.85 USD/bbl Oil WTI-WCS 2025: 11,700 bbl/d @ -14.26 USD/bbl Oil Brent 2025 Jan: 1,000 bbl/d @ 75.00 USD/bbl 2025 Feb-Dec: 2,000 bbl/d @ 75.78 USD/bbl Gas 2025 Jan-Dec: 9,600 Mcf/d @ 2.60 CAD/Mcf 2025 Apr-Oct: 19,300 Mcf/d @ 2.34 CAD/Mcf FX 2025: MCAD 520 @ 1.36 MMYR 138 @ 4.40 MEUR 27 @ 1.07 20
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NC00408 p11 02.26See Notes and Reader Advisory International Petroleum Corp. 2025 Highlights Capital Expenditure MUSD MUSD 228 344 Blackrod Phase1 FY2025 Production Mboepd44.9 Mboepd45.6Q4 FY2025 Stable Operating Costs Q4 FY2025 18.4 USD/boe 17.8 USD/boe Robust Cash Flow 259 MUSD OCF MUSD FCF(153) FY2025 FY2025 Balance Sheet Net Debt 484 Bonds Refinanced MUSD Sustainability Focus material incidentsNo Share Repurchase 2024/25 NCIB million shares cancelled7.7 21
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Notes Page 2: Q4 and Full Year 2025 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 10, 2026 (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, 2025 (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 344 million includes decommissioning expenditure of USD 7 million. • NCIB 2024/2025 includes 0.3 million IPC shares purchased under other exemptions in Canada. Page 3: 2025 Production and Operating Expenditure • For production figures, see Reader Advisory, including “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory”. • Operating costs is a “Non-IFRS Measure”. See Reader Advisory and MD&A. Page 4: 2025 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: 2025 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, 2025. See Reader Advisory and MCR, including “Reserves and Resources Advisory”. • NCIB 2024/2025 includes 0.3 million IPC shares purchased under other exemptions in Canada. Page 9: Financial Highlights • Operating costs, OCF, EBITDA, FCF and net debt are “Non-IFRS Measures”. See Reader Advisory and MD&A. • Capital expenditure of USD 344 million includes decommissioning expenditure of USD 7 million. Page 12: Financial Results – Operating Cash Flow & EBITDA • OCF and EBITDA are “Non-IFRS Measures”. See Reader Advisory and MD&A. Page 13: Operating Costs • Operating costs is a “Non-IFRS Measure”. See Reader Advisory and MD&A. Page 14: 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 15: Net Cash/Debt (MUSD) • OCF and net cash / net debt are “Non-IFRS Measures”. See Reader Advisory and MD&A. Page 16: 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 21: 2025 Highlights • See Notes to Page 2: “Q4 and Full Year 2025 Highlights” 22
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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: • 2026 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 maintain current and forecast production in France and Malaysia; • The intention and ability of IPC to acquire 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; • IPC’s ability to implement its greenhouse gas (GHG) emissions intensity and climate strategies and to achieve its net GHG emissions intensity reduction targets; • IPC’s ability to implement projects to reduce net emissions intensity, including potential carbon capture and storage; • Estimates of reserves and contingent resources; • The ability to generate free cash flows and use that cash to repay debt; • IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the Corporation; • IPC’s ability to 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, tariffs, 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: the potential impact of tariffs implemented in 2025 by the U.S. and Canadian governments and that other than the tariffs that have been implemented, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve and contingent resource volumes; operating costs; our ability to maintain our existing credit ratings; our ability to achieve our performance targets; the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions and that we will be able to implement our standards, controls, procedures and policies in respect of any acquisitions and realize the expected synergies on the anticipated timeline or at all; the benefits of acquisitions; the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally; the availability and cost of financing, labour and services; our intention to complete share repurchases under our normal course issuer bid program, including the funding of such share repurchases, existing and future market conditions, including with respect to the price of our common shares, and compliance with respect to applicable limitations under securities laws and regulations and stock exchange policies; and the ability to market crude oil, natural gas and natural gas liquids successfully. Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: • general global economic, market and business conditions; • the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; • delays or changes in plans with respect to exploration or development projects or capital expenditures; • the uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses; • health, safety and environmental risks; • commodity price fluctuations; • interest rate and exchange rate fluctuations; • marketing and transportation; • loss of markets; • environmental and climate-related risks; • competition; • innovation and cybersecurity risks related to our systems, including our costs of addressing or mitigating such risks; • the ability to attract, engage and retain skilled employees; • incorrect assessment of the value of acquisitions; • failure to complete or realize the anticipated benefits of acquisitions or dispositions; 23
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Reader Advisory • the ability to access sufficient capital from internal and external sources; • failure to obtain required regulatory and other approvals; • geopolitical conflicts, including current and potential future conflicts in Ukraine, the Middle East, South America and elsewhere, and their potential impact on, among other things, global market conditions; • political or economic developments, including, without limitation, the risk that (i) one or both of the U.S. and Canadian governments increases the rate or scope of tariffs implemented in 2025, or imposes new tariffs on the import of goods from one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Corporation; 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. 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, 2025 (MD&A) (See “Risks Factors”, “Cautionary Statement Regarding Forward-Looking Information” and “Reserves and Resources Advisory”), the Corporation’s material change report dated February 10, 2026 (MCR), the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2024 (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 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. 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 and France/Malaysia are effective as of December 31, 2025, and are included in the reports prepared by Sproule International Limited and ERC Equipoise Ltd., respectively (collectively, Sproule ERCE), an independent qualified reserves evaluator and auditor, 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 ERCE’s December 31, 2025 price forecasts. The price forecasts used in the Sproule ERCE reports are available on the website of Sproule ERCE (sproule-erce.com) and are contained in the MCR. These price forecasts are as at December 31, 2025 and may not be reflective of current and future forecast commodity prices. 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. 24
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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 ERCE in respect of IPC’s oil and gas assets in Canada, France and Malaysia have been aggregated. 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. 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, 2025, which will be filed on SEDAR+ (accessible at www.sedarplus.ca) on or before April 1, 2026. 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. 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 (Mboepd) Light and Medium Crude Oil (Mboepd) Conventional Natural Gas (per day) Total (Mboepd) Three months ended December 31, 2025 23.9 6.6 90.9 MMcf (15.1 Mboe) 45.6 December 31, 2024 24.3 7.1 95.9 MMcf (16.0 Mboe) 47.4 Year ended December 31, 2025 23.6 6.4 89.6 MMcf (14.9 Mboe) 44.9 December 31, 2024 23.9 7.7 95.1 MMcf (15.8 Mboe) 47.4 This presentation also makes reference to IPC’s forecast total average daily production of 44,000 to 47,000 boepd for 2026. IPC estimates that approximately 57% of that production will be comprised of heavy crude oil, approximately 12% will be comprised of light and medium crude oil and approximately 31% will be comprised of conventional natural gas. 25
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Reader Advisory Currency All dollar amounts in this presentation are expressed in United States dollars, except where otherwise noted. Currency Abbreviations CAD Canadian dollar MCAD Million Canadian dollar EUR Euro MEUR Million Euro USD US dollar MUSD Million US dollar MYR Malaysian Ringgit MMYR Million Malaysian Ringgit Oil related terms and measurements AECO The daily average benchmark price for natural gas at the AECO hub in southeast Alberta AESO Alberta Electric System Operator API An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale ASP Alkaline surfactant polymer (an EOR process) bbl Barrel (1 barrel = 159 litres) 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 FPSO Floating Production Storage and Offloading facility 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 WTI West Texas Intermediate WCS Western Canadian Select 26
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