Slides
Page 1
NC00249 p01 02.22 Operations & Financial Update Third Quarter 2026 William Lundin, CEO Christophe Nerguararian, CFO November 3, 2026 Q 26 3
Page 2
International Petroleum Corp. Third Quarter 2026 Highlights NC00434 p18 10.26 See Notes and Reader Advisory Organic growth Hedging Production guidance Blackrod Phase 1 successfully delivered on budget, ahead of schedule with positive ramp-up progression 2026 capital expenditure adjusted to 185 MUSD, additional project activity in Canada Fully exposed to Brent and WTI prices after Q2 Canadian heavy oil differential exposure partially hedged in 2026 and 2027 Share Repurchase 1.3 million shares repurchased under current NCIB program, intention to renew for 2026/2027 Net debt of 473 MUSD, 10% reduction in leverage compared to prior quarter Available liquidity of greater than 200 MUSD Non-core asset sale for 70 MCAD (net gain of 62 MCAD) Q3 average net production of 44,000 boepd, in line with guidance for the quarter 2026 net production guidance maintained at 44,000 – 47,000 boepd Cash flow Strong Q3 Operating Cash Flow (OCF) of 79 MUSD 2026 OCF forecast of 275–350 MUSD (@ Brent 80–110 USD/bbl for the remainder of 2026) Q3 Free Cash Flow (FCF) of 27 MUSD 2026 FCF forecast of 35–110 MUSD (@ Brent 80–110 USD/bbl for the remainder of 2026) Liquidity Q3 operating costs in line with forecast for the period at 21 USD/boe Full year forecast guidance range maintained at 18–20 USD/boeOperating costs 2
Page 3
NC00434 p10 10.26See Notes and Reader Advisory International Petroleum Corp. Production and Operating Costs Guidance 2026 Forecast 2026 Actual Full Year 2026 Forecast Full Year 2025 Full Year 2024 Oil Brent Oil WCS Gas Average Net Production (Mboepd) Q1 Q2 Q3 Q4 Low guidance High guidance Guidance range 47 44 Low High 44.9 43.0 42.2 44.045 43 2026 average production guidance range maintained at 44 to 47 Mboepd 2026 Operating Costs Guidance International, 10% Canada Gas, 31% Canada Crude, 59% 2026 Forecast Production Guidance W CS Gas Brent Material production growth forecast in Q4 2026 continuing into 2027 48 46 47.4 3
Page 4
NC00434 p20 10.26 International Petroleum Corp. 2026 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 100 MUSD 55 USD/bbl (4/13) (1) 250 MUSD 75 USD/bbl (5/14) (1) 275 MUSD 214 MUSD 94 USD/bbl (10/14) (1) First 9M 2026 2026 CMD guidance2026 Forecast @ 80 USD/bbl (5/22) (1) Q2 Q3 79 MUSD 97 USD/bbl (11/14) (1) Q1 350 MUSD 2026 Forecast @ 110 USD/bbl (10/22) (1) 4
Page 5
NC00434 p03 10.26 International Petroleum Corp. 2026 Capital Expenditure See Notes and Reader Advisory Canada 157 MUSD •Blackrod •Other assets •Abandonment 112 40 5 International 28 MUSD •France •Malaysia 25 3 Blackrod Other assets Abandonment 112 68 5 2026 Expenditure 185 MUSD Phase 1 project Sustaining capital well pairs 41-46 Capitalized operations Resource maturation 35 31 36 10 Blackrod 112 MUSD FRANCE MALAYSIA Capital expenditure budget increased to 185 MUSD Production well drilling completed in Canada and France Accelerated Onion Lake Thermal infills Additional Blackrod resource maturation 5
Page 6
NC00434 p05 10.26 International Petroleum Corp. 2026 Free 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 2026 CMD FCF Guidance 2026 Forecast FCFFirst 9M 2026 FCF 14 MUSD 94 USD/bbl (10/14) (1) -70 MUSD 55 USD/bbl (4/13) (1) 85 MUSD 75 USD/bbl (5/14) (1) 35 MUSD 80 USD/bbl (5/22) (1) 110 MUSD 110 USD/bbl (10/22) (1) 6
Page 7
NC00434 p06 10.26 International Petroleum Corp. Share Repurchase See Notes and Reader Advisory Shares Outstanding at Spin off April 2017 Shares Outstanding @ end October 2026 SIB 2017 NCIB 2019/2020 2021/2022 NCIB 2022/2023 2023/2024 2024/2025 2025/2026 SIB 2022 113.5 Million IPC shares +75.8 -25.5 No Dilution -18 -8.3 -26.7 111.5 BlackPearl Acquisition December 2018 ~4.5x production >1 billion boe (CR) 4x Net Asset Value +23 years added to reserves life 18x 2P reserves 78 million IPC shares repurchased since inception at an average price of SEK 81 / CAD 11 per share Greater than USD 1.3 billion of value created from total share repurchases compared to current share price 1.3 million shares repurchased under 2025/2026 NCIB, intention to renew NCIB to December 2027 7
Page 8
See Notes and Reader Advisory First oil achieved in Q2 2026 Ahead of original schedule guidance set in 2023 Project delivered on budget Total growth capital spend to first oil of 855 MUSD Phased production start and ramp-up through 2H 2026 12 production well pairs online at end Q3 2026 IPC Canada Blackrod Phase 1 Progress Update T77 0 20.5 Kilometers 0 11/4 Miles YE25 Reserves Pads Drilled Wells Spot rate CPF / Well Pads 1A Nth 1A Nth 1A Sth 1A Sth 1B Nth 1B Nth 1B Sth 1B Sth 0 5 10 Blackrod Production Blackrod pilot Blackrod commercial 2026 Jan Feb Mar Apr May Jun Jul Aug Sep NC00434 p12 10.26 Production (Mbopd) 8
Page 9
IPC Canada Blackrod Overview NC00434 p13 10.26 Phase 1 Working Interest MMbbl 30 Mbopd Plateau Forecast Production 2P Reserves MMbbl 311 Full Field 80 Mbopd Regulatory Approved Production Resources Bn bbl 1.45 Ownership 100% 2C Resources 1,142 Phase 1 First Oil – May 31, 2026 See Notes and Reader Advisory 0 200 400 600 800 1,000 1,200 1,400 1,500 YE10 YE11 YE12 YE13 YE14 YE15 YE16 YE17 YE18 YE19 YE20 YE21 YE22 YE23 YE24 YE25 2C contingent resources 2P reserves Evolution Blackrod Recoverable Resources (2P + 2C) MMbbls > 2x increase in recoverable resources Blackrod 0 0 2 KM Miles 4 Liquids, gas and condensate export pipelines CPF Phase 1YE 2024 YE 2025 Blackrod Reservoir Blackrod Total Area, km2 130 In-place volume, MMboe 2,936 Total recoverable (2P+2C), MMboe RF Appraisal wells, # 1,453 50% 113 Blackrod Phase 1 (Initial Development Area) Area, km 2 22 In-place volume, MMboe 624 Total recoverable (2P), MMboe Appraisal wells, # 311 50% 60 RF 9
Page 10
IPC Canada Onion Lake Thermal NC00434 p14 10.26See Notes and Reader Advisory - 2 4 6 8 10 Production (Mboepd) 12 14 Onion Lake Thermal Production 2019 2020 2021 2022 2023 2026 Q1 Q2 Q32024 2025 Q3 2026 production in line with guidance Drilling of 2 additional production infill wells Wells are expected online towards the end of Q4 2026 HH HH LL EED’D’ AA BB FF CC Well path 2025 wells Q4 2026 Infill wells Reservoir OLT main facility Pads Onion Lake Thermal area Infill wells Alberta Saskatchewan 10
Page 11
IPC Canada Suffield Area Assets NC00434 p15 10.26See Notes and Reader Advisory Suffield Area Oil and Gas Production Production (Mboepd) 2026 10 5 0 - 15 20 25 2025 Successful execution of 4 new Basal Quartz production wells with initial results in line with expectations Stable low decline production Jan Feb AprMar Jan Feb MarMay Jun Apr May JunJul Aug Sep Jul Aug SepOct Nov Dec Suffield Brooks assets Suffield Oil area Suffield Gas area CFB Suffield Redcliff Medicine Hat Suffield Alderson 0 KM 20 Basal Quartz Fairway (Ellerslie ) Ellerslie fields Ellerslie Fairway Suffield Area Assets 11
Page 12
NC00434 p21 10.26See Notes and Reader Advisory IPC International Assets Overview International Production (Net IPC) Production (Mbopd) Production (bopd) 0 2 4 6 1 3 5 France Malaysia High quality light oil exposed to Brent pricing Bertam field in Malaysia commanding record premium to Dated Brent in 2026 Paris Basin capital activity completed, FAB field unlocked with horizontal drilling 2026 2026 Jan Feb Mar JunApr May Jun Jul Aug SepJul Aug Sep 2025 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Oct Nov Dec Provins Vitry-le-François Mailly-Le-Camp Sézanne Châlons-en- Champagne Provins Vitry-le-François Mailly-Le-Camp Sézanne Châlons-en- Champagne Merisier Courdemanges Grandville MclaunayMclaunay 0 KM 10 Dommartin-Lettrée Villeseneux Amaltheus Vert-la-Gravelle Soudron La Motte Noire Villeperdue (VPU) Fontaine-au-Bron (FAB) France - Paris Basin 0 200 400 600 800 1,000 France - FAB6ST Production Daily oil rate Forecast 0 KM 4 4 Fontaine-au-Bron Villeperdue FAB3 FAB6ST FAB16G VPU I16H 12
Page 13
Third Quarter 2026 Financial Highlights 13
Page 14
Third Quarter 2026 First Nine Months 2026 Production (boepd) 44,000 43,100 Average Dated Brent Oil Price (USD/bbl) 96.7 93.8 Operating costs (USD/boe) 20.9 19.2 Operating cash flow (MUSD) 79.4 213.6 EBITDA (MUSD) 79.4 207.5 Capital Expenditure (MUSD) 37.3 157.1 Free cash flow (MUSD) 27.4 14.2 Net result (MUSD) 59.9 82.6 See Notes and Reader Advisory Net debt (MUSD) 472.8 14 First Nine Months 2026 Financial Highlights
Page 15
Malaysia liftings: Q1 - 2026 - 1 cargo => March Q2 - 2026 - 1 cargo => June Q3 - 2026 - 1 cargo => September 2026 2025 2025 2024 USD/bbl YTD Q3 Q2 Q1 Q4 Q3 Q2 Q1 Full Year Full Year Brent 93.8 96.7 103.8 81.1 63.7 69.1 67.9 75.7 69.1 80.7 Malaysia 112.8 (+19.0) 126.9 (+30.2) 103.7 (-0.1) 110.1 (+29.0) 67.7 (+4.0) 74.5 (+5.4) 67.3 (-0.6) 78.8 (+3.1) 71.5 (+2.4) 86.1 (+5.4) France 88.2 (-5.6) 97.0 (+0.3) 101.1 (-2.7) 73.9 (-7.2) 64.1 (+0.4) 69.5 (+0.4) 68.5 (+0.6) 75.8 (+0.1) 69.6 (+0.5) 80.0 (-0.7) WTI 83.4 85.6 92.3 72.4 59.2 65.0 63.8 71.5 64.8 75.7 WCS (calculated) 69.2 (-14.2) 71.8 (-13.8) 77.7 (-14.6) 58.2 (-14.2) 48.0 (-11.2) 54.6 (-10.4) 53.6 (-10.2) 58.8 (-12.7) 53.7 (-11.1) 60.9 (-14.8) Suffield 68.6 (-0.6) 70.7 (-1.1) 78.2 (+0.5) 57.1 (-1.1) 47.3 (-0.7) 54.4 (-0.2) 52.7 (-0.9) 57.8 (-1.0) 53.1 (-0.6) 60.9 (–) Onion Lake 68.6 (-0.6) 70.4 (-1.4) 78.2 (+0.5) 57.8 (-0.4) 47.6 (-0.4) 54.1 (-0.5) 53.4 (-0.2) 58.3 (-0.5) 53.3 (-0.4) 60.7 (-0.2) 15 First Nine Months 2026 Realized Oil Prices
Page 16
1 0 2 3 4 5 6 7 8 1 -1 0 2 3 4 5 6 7 8 CAD/Mcf USD/Mbtu Jan Feb Mar Apr Aug Sep Oct Nov Sep Oct Nov Sep Oct NovDec Dec 2024 2025 2026 May Jun Apr May JunJul Aug Jul Jun Aug JulJan Feb Mar Apr MayJan Feb Mar Empress / AECO differential AECO Day Ahead Index Realized Price CAD/Mcf Henry Hub Price USD/Mbtu AECO Empress Realized (to AECO) 2024 1.44 1.49 1.51 (+0.07) Full Year 20252026 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 1.98 2.47 2.51 (+0.53) Q1 1.61 1.60 1.75 (+0.14) Q2 1.55 1.52 1.58 (+0.03) Q3 1.71 1.86 1.94 (+0.23) YTD 2025 1.63 1.84 1.87 (+0.24) Full YearCAD/Mcf 2.52 1.17 0.72 1.61 2.40 0.84 2.51 1.75 1.58 NC00433 p01 1.82 2.46 16 First Nine Months 2026 Realized Gas Prices
Page 17
NC00434 fin p01 10.26 EBITDAOperating Cash Flow 207214 Q1 64 Q2 64 Q3 79 Q1 68 Q3 79 Q2 67 100 150 50 200 250 0 100 150 50 200 250 0 Million USD Million USD 2026 20262025 2025 196 185 Q1 75 Q2 55 Q3 66 Q1 71 Q2 52 Q3 62 See Notes and Reader Advisory 17 First Nine Months 2026 Financial Results – Operating Cash Flow and EBITDA
Page 18
NC00434 fin p02 10.26 12 10 14 16 1818 20 22 24 12 10 14 16 20 22 24 2626 Q1 2026 Actual Q2 2026 Actual Q3 2026 Actual Q4 2026 Forecast USD/boe USD/boeQuarterly operating costs 2026 Operating Costs Guidance: 18–20 USD/boe See Notes and Reader Advisory 18 First Nine Months 2026 Operating Costs
Page 19
Third Quarter 2026 First Nine Months 2026 Average Dated Brent oil price (96.7 USD/bbl) (93.8 USD/bbl) Revenue 52.4 48.6 Cost of operations -17.9 -16.3 Tariff and transportation -2.7 -2.6 Production taxes -0.3 -0.3 Operating costs -20.9 -19.2 Cost of blending -10.9 -11.1 Inventory movements -0.1 0.4 Revenue – production costs 20.5 18.7 Cash taxes -1.0 -0.5 Operating cash flow 19.5 18.2 General and administration costs -1.0 -1.0 EBITDA 19.5 17.7 See Notes and Reader Advisory 19 First Nine Months 2026 Netback (USD/boe)
Page 20
(440) (460) (480) (340) (360) (380) (240) (260) (280) (420) (520) (400) (320) (300) (500) (440) (460) (480) (340) (360) (380) (240) (260) (280) (420) (520) (400) (320) (300) (500) MUSD MUSD Operating Cash Flow MUSD 213.6 Net Cash Financial Items MUSD -30.0 Sale of Assets MUSD 51.4 Development Capex & Abex MUSD -157.1 Cash G&A MUSD -11.8 Share buyback MUSD -27 Opening Net Debt 1 Jan 2026 MUSD -483.6 Closing Net Debt 30 Sep 2026 MUSD -472.8 Change in Working Capital MUSD -28.3 NC00433 p02 Blackrod MUSD 107.0 See Notes and Reader Advisory 20 First Nine Months 2026 Net Debt (MUSD)
Page 21
MUSD Third Quarter 2026 First Nine Months 2026 Net interest expense 9.6 28.9 Amortisation of capitalised financing fees 0.6 1.7 Unwinding of asset retirement obligation discount 4.1 12.4 Foreign exchange loss (gain), net and others -1.7 12.7 Net Financial Items 12.6 55.7 MUSD Third Quarter 2026 First Nine Months 2026 G&A 4.0 11.8 G&A – Depreciation 0.4 1.1 G&A Expense 4.4 12.9 See Notes and Reader Advisory 21 First Nine Months 2026 G&A / Financial Items
Page 22
NC00434 fin p03 10.26 200 100 50 400 300 250 150 350 500 450 550 600 50 0 200 100 400 300 250 150 350 500 450 550 600 0 Million USD Million USD Revenue MUSD 570.7 43,100 boepd Depletion MUSD -89.2 Production costs MUSD -351.9 19.2 USD/boe G&A MUSD -12.9 Tax MUSD -28.4 Other income/(expense) MUSD 0.6 Sale of Assets MUSD 51.4 Financial items MUSD -55.7 Exploration and Business Development costs MUSD -2 Net result MUSD 82.6 Gross profit MUSD 127.6 Cash Margin MUSD 218.8 See Notes and Reader Advisory 22 First Nine Months 2026 Financial Results
Page 23
MUSD 30 Sep 2026 31 Dec 2025 Assets Oil and gas assets 1,796.1 1,798.2 Other non-current assets 51.0 49.1 Current assets 188.7 123.3 Cash 22.3 7.0 2,058.1 1,977.6 Liabilities Financial liabilities 45.1 38.7 Bonds (net of capitalised fees) 443.5 442.3 Provisions 283.2 284.2 Other non-current liabilities 145.2 125.0 Current liabilities 194.4 160.2 Equity 946.7 927.2 2,058.1 1,977.6 23 30 September 2026 Balance Sheet
Page 24
International Petroleum Corp. Capital Structure Maturity May 2028 Drawdown at September 30, 2026: MCAD 64 (MUSD 45) MCAD 11.9 letters of credit issued Bonds MUSD 450 Maturity October 2030 7.50% coupon Interest payable April and October Canadian RCF MCAD 348.5 Letter of Credit Facility See Notes and Reader Advisory 24
Page 25
International Petroleum Corp. Hedging - 2026/2027 2026-2027 Hedges Executed Oil Brent 2026 Feb-Jun: 1,500 bbl/d @ 66.67 USD/bbl 2026 Mar-Jun: 500 bbl/d @ 72.25 USD/bbl Oil WTI 2026 Feb-Jun: 7,500 bbl/d @ 61.53 USD/bbl 2026 Mar-Jun: 1,500 bbl/d @ 66.50 USD/bbl Oil WTI-WCS 2026: Diff. 5,000 bbl/d @ -12.50 USD/bbl 2026 Jul-Dec: Quality diff. 2,000 bbl/d @ -3.65 USD/bbl 2026 Jul-Dec: Hardisty to Houston transport diff. 5,000 bbl/d @ -7.55 USD/bbl 2027: Hardisty to Houston transport diff. 5,000 bbl/d @ -7.55 USD/bbl Hardisty to Houston transport diff. 5,000 bbl/d @ -7.50 USD/bbl Gas 2026 Apr-Oct: 15,000 GJ/d @ 2.73 CAD/GJ Currency Hedging 2027: Sell MUSD 120 @ 1.38 (buy CAD) Sell MEUR 15.6 @ 1.14 (buy USD) Sell MMYR 76 @ 4.03 (buy USD) 25
Page 26
NC00434 p19 02.26See Notes and Reader Advisory International Petroleum Corp. Conclusion Annual report published in August Production Resource Cash Flow Generation 2026 Production Guidance 44–47 Mboepd 521 27% absolute share reduction since January 1, 2022 5 acquisitions since inception Non-core asset sale 70 MCAD in Q3 1,224 275 to 350 MUSD 2026 OCF 50% production growth by 2028 Balance Sheet Shareholders Return Sustainability M&A 200 MUSD liquidity 10% reduction in leverage to prior quarter MMboe2P 2C MMboe 26
Page 27
Notes Page 2: Q3 2026 Highlights • For production figures, see Reader Advisory, including “Supplemental Information regarding Product T ypes” in “Reserves and Resources Advisory” and the annual information form for the year ended December 31, 2025 (AIF) 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 three and nine months ended September 30, 2026 (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 185 million includes decommissioning expenditure of USD 5 million. Page 3: Production and Operating Costs Guidance • For production figures, see Reader Advisory, including “Supplemental Information regarding Product T ypes” in “Reserves and Resources Advisory”. • Operating costs is a “Non-IFRS Measure”. See Reader Advisory and MD&A. Page 4: 2026 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: 2026 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 AIF, including “Reserves and Resources Advisory”. • 2P reserves and contingent resources (best estimate, unrisked) are as at December 31, 2025. See Reader Advisory and AIF, including “Reserves and Resources Advisory”. • NCIB 2024/2025 includes 0.3 million IPC shares purchased under other exemptions in Canada. • Shares outstanding at October 2026 includes 0.6 million IPC shares issued during Q1 2026. • Current IPC share price is based on close at October 30, 2026 (280.0 SEK/share and exchange rate of 9.83 SEK/USD). Page 8: Blackrod Phase 1 Progress Update • For risks and uncertainties related to the Blackrod Phase 1 project, see Reader Advisory, MD&A and AIF . Page 9: Blackrod Overview • For risks and uncertainties related to the Blackrod project, see Reader Advisory, MD&A and AIF . • 2P reserves and contingent resources (best estimate, unrisked) are as at December 31, 2025. See Reader Advisory and AIF, including “Reserves and Resources Advisory”. • In respect of estimated production, see Reader Advisory and AIF. • NPV is after tax, discounted at 10% and based on the forecast prices and other assumptions further described in the AIF. Page 10: Onion Lake Thermal • For production figures, see Reader Advisory and AIF, including “Reserves and Resources Advisory”. Page 11: Suffield Area Assets • For production figures, see Reader Advisory and AIF, including “Reserves and Resources Advisory”. Page 12: International Assets Overview • For production figures, see Reader Advisory and AIF, including “Reserves and Resources Advisory”. Page 14: Financial Highlights • Operating costs, OCF, EBITDA, FCF and net debt are “Non-IFRS Measures”. See Reader Advisory and MD&A. • First Nine months 2026 capital expenditure of USD 157 million includes decommissioning expenditure of USD 2 million. Page 17: Financial Results – Operating Cash Flow and EBITDA • OCF and EBITDA are “Non-IFRS Measures”. See Reader Advisory and MD&A. Page 18: Operating Costs • Operating costs is a “Non-IFRS Measure”. See Reader Advisory and MD&A. Page 19: 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 20: Net Debt (MUSD) • OCF and net debt are “Non-IFRS Measures”. See Reader Advisory and MD&A. Page 21: 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 26: Conclusion • See Notes to Page 2: “Q3 2026 Highlights”. • Production growth is compared to net average daily production for the first nine months of 2026. • 2P reserves and contingent resources (best estimate, unrisked) are as at December 31, 2025. See Reader Advisory and AIF, including “Reserves and Resources Advisory”. 27
Page 28
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 IPC’s 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, net present values and future phase developments; • Current and future production performance, operations and development potential of the Onion Lake Thermal, Suffield, Brooks and Ferguson 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 renew the NCIB and the number of common shares which may be purchased under a renewed NCIB; • 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 GHG 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 Corporat ion; • 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. 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: the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, 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; IPC’s ability to maintain its existing credit ratings; IPC’s ability to achieve its 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 IPC will be able to implement its 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; IPC’s intention to complete share repurchases under the normal course issuer bid program, including the funding of such share repurchases, existing and future market conditions, including with respect to the price of IPC’s 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 IPC’s systems, including costs of addressing or mitigating such risks; the ability to attract, engage and retain skilled employees; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; the ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; geopolitical conflicts, including 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) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, 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 or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S. will trigger a broader global trade war which 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, including by decreasing demand for, and the price of oil, and natural gas, disrupting supply chains, increasing costs, causing volatility in the global financial markets, and limiting access to financing; 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 and nine months ended September 30, 2026 (MD&A) (See “Risks Factors”, “Cautionary Statement Regarding Forward-Looking Information” and “Reserves and Resources Advisory”), the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2025 (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. 28
Page 29
Reader Advisory Estimated production and FCF generation are based on IPC’s current business plans over the periods of 2026 to 2030 and 2031 to 2035, less net debt of USD 484 million as at December 31, 2025, with assumptions based on the reports of IPC’s independent reserves evaluator and auditor, and including certain corporate adjustments relating to estimated general and administration costs and hedging, and excluding shareholder distributions and certain refinancing costs. Assumptions include average net production of approximately 62 Mboepd over the period of 2026 to 2030, average capital expenditures of approximately USD 5 per boe, average operating costs of approximately USD 18 to 20 per boe, average Brent oil prices of USD 65 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 auditor and as further described in the AIF. IPC’s current business plans and assumptions, and the business environment, are subject to change. Actual results may differ materially from forward-looking estimates and forecasts. 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 AIF. These price forecasts are as at December 31, 2025 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 521 MMboe as at December 31, 2025, by the mid-point of the 2026 production guidance of 44,000 to 47,000 boepd. The product types comprising the 2P reserves and contingent resources described in this presentation are contained in the AIF. See also “Supplemental Information regarding Product Types” below. Light, medium and heavy crude oil and bitumen reserves/resources disclosed in this 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. There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the best estimate. Contingent resources are further classified based on project maturity. The project maturity subclasses include development pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources are classified as either development on hold or development unclarified. Development on hold is defined as a contingent resource where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator. Development unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until commercial contingencies can be clearly defined. Chance of development is the probability of a project being commercially viable. Where risked resources are presented, they have been adjusted based on the chance of development by multiplying the unrisked values by the chance of development. References to “unrisked” contingent resources volumes means that the reported volumes of contingent resources have not been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook for contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies required for the re-classification of the contingent resources as reserves being resolved. Therefore unrisked reported volumes of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such resources. The contingent resources reported in this 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 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 reserves and resources evaluations will be attained and variances could be material. 29
Page 30
Reader Advisory 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 September 30, 2026 24.7 5.5 83.1 MMcf (13.8 Mboe) 44.0 September 30, 2025 24.5 6.5 89.3 MMcf (14.9 Mboe) 45.9 Nine months ended September 30, 2026 23.2 5.8 84.6 MMcf (14.1 Mboe) 43.1 September 30, 2025 23.5 6.3 89.1 MMcf (14.8 Mboe) 44.6 Year ended December 31, 2025 23.6 6.4 89.6 MMcf (14.9 Mboe) 44.9 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. Currency All dollar amounts in this presentation are expressed in United States dollars, except where otherwise noted. Currency Abbreviations Oil related terms and measurements CAD Canadian dollar AECO The daily average benchmark price for natural gas at the AECO hub in southeast Alberta Mbbl Thousand barrels MCAD Million Canadian dollar AESO Alberta Electric System Operator MMbbl Million barrels EUR Euro API An indication of the specific gravity of crude oil on the API (American Petroleum Institute) gravity scale Mboe Thousand barrels of oil equivalents MEUR Million Euro ARV Argus WCS Houston (represents the differential, in USD, between a barrel of WCS quality in Houston and WTI) Mboepd Thousand barrels of oil equivalents per day USD US dollar ASP Alkaline surfactant polymer (an EOR process) Mbopd Thousand barrels of oil per day BUSD Billion US dollar bbl Barrel (1 barrel = 159 litres), MMboe Million barrels of oil equivalents MUSD Million US dollar boe Barrels of oil equivalents MMbtu Million British thermal units MMYR Million Malaysian Ringgit boepd Barrels of oil equivalents per day Mcf Thousand cubic feet bopd Barrels of oil per day Mcfpd Thousand cubic feet per day Bcf Billion cubic feet MMcf Million cubic feet C5 Condensate MW Megawatt CO2e Carbon dioxide equivalents, including carbon dioxide, methane and nitrous oxide MWh Megawatt hour Empress The benchmark price for natural gas at the Empress point at the Alberta/Saskatchewan border NGL Natural gas liquid EOR Enhanced Oil Recovery SAGD Steam assisted gravity drainage FPSO Floating Production Storage and Offloading facility WTI West Texas Intermediate GJ Gigajoules WCS Western Canadian Select 30
Page 31
www.international-petroleum.com Follow us on social media 31