Slides
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CORPORATE PRESENTATION Generating Strong Returns Through Commodity Price Cycles February 2026
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2 2 Refer to Slide Notes and Advisories. All amounts in this presentation are in Canadian dollars. 1. Current Market Capitalization. 2. 2026E Canadian Natural Gas Production (mmcf/d). Source: Peters & Co. Research and Company Reports. ~$17 Billion Market Capitalization ~$20 Billion Enterprise Value 372,500 boe/d 2026 Production Guidance $3.3 Billion 2026 Funds Flow $2.05 Billion 2026 Capital Budget $3.4 Billion Dec. 31st, 2025 Net Debt 1.0x Net Debt / Funds Flow $0.73 per Share Annual Dividend ($0.0608/month) CORPORATE OVERVIEW 7th Largest Canadian Oil & Gas Producer1 5th Largest Canadian Natural Gas Producer2
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2025 FINANCIAL & SHAREHOLDER HIGHLIGHTS Delivered 15% Total Shareholder Return • 6% Production per share growth + 7% dividend yield + 2% share repurchases Returned $929 million to Shareholders in 2025 • $736 million base dividends ($0.73/share) • $193 million share repurchases Generated Record Funds Flow of $2.9 billion ($2.95/sh) • Free funds flow of $889 million Maintained Investment Grade Balance Sheet Strength • Net debt to funds flow <1.0x • $1.5 billion available liquidity 3 Refer to Slide Notes and Advisories
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2025 OPERATIONAL & STRATEGIC EXECUTION Record Annual Production of 307,245 boe/d • Strong performance across core assets Operational Execution Supported Guidance Increases • Accelerated timing on new wells • Supported by strong technical analysis and well design enhancements Seamless Integration of Veren Assets • Realized synergies increased to $300 million, up from $210 million original estimate Enhanced Scale, Inventory Depth & Long-Term Sustainability • Lower costs and increasing profit margins • Exposure to oil/condensate, liquids rich and lean gas assets to maximize returns through commodity cycles 4 Refer to Slide Notes and Advisories
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5 5 Refer to Slide Notes and Advisories 2025 RESERVE REPORT HIGHLIGHTS Resource Capture Record 2.2 billion boe of proved + probable (2P) reserves Reserve growth driven by Veren Combination and continued organic development Sustainability Long duration reserve base with 16+ year Reserve Life Index Exceptional production replacement Capital Efficiency & Upside Conservative booking supports significant future inventory upside Low Cost Structure PDP 1P 2P 383% 687% 1,011% 2P F&D 2P FD&A $17.17/boe $15.81/boe 1.7x Recycle Ratio 1.9x Recycle Ratio
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6 6 Refer to Slide Notes and Advisories WHY OWN WHITECAP Total Shareholder Return Target of 10% – 15% Annually Premium Portfolio • Depth & Breadth of Inventory Across Multiple Plays • ~5,800 primarily light oil conventional drilling locations • ~4,700 unconventional Montney and Duvernay locations (oil/liquids rich to lean gas) Large Resource • Inventory Rich • PDP (700 Million boe), 1P (1.5 Billion boe) and 2P (2.2 Billion boe) reserves • Long RLI • 2P RLI equates to 16.1 years Size & Scale • 7th Largest Canadian Producer • Largest Alberta Montney and Duvernay landholder with 1,500,000 acres • 5th largest Canadian Natural Gas producer • Largest light oil producer in Saskatchewan Balance Sheet Strength • Low Leverage • ~1.0x Net Debt/Funds Flow • Investment Grade Credit Rating of BBB by DBRS • Fully Funded Model
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7 CAPITAL ALLOCATION TOOLKIT Refer to Slide Notes and Advisories Share Repurchases • After-tax cost of debt vs equity • Share price vs intrinsic value • Permanent improvement to capital structure Base Dividend • Meaningful return of capital mechanism • Target payout ratio of 20% – 25% • Grow with the business longer term Balance Sheet • Target Net Debt / Funds Flow of 1.0x or less • Stress test leverage to US$50/bbl WTI Production Growth • 3% – 5% per share per annum dependent on commodity prices • Higher growth as returns increase Capital Allocation Considerations 7
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8 500 000 $50 $55 $60 $65 $70 $75 $80 WTI (US$/bbl) COUNTER CYCLICAL APPROACH Refer to Slide Notes and Advisories Share Repurchase Focus • Maintain current production • Prioritize share repurchases below intrinsic value Balanced Approach • Production growth + share repurchases + balance sheet Balance Sheet Focus • Target moderate production growth • Prioritize balance sheet to capture future opportunities Low leverage, long inventory life, & scale allows counter-cyclical investing through commodity cycles Annual Free Funds Flow 8
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9 Optimizing drilling programs, enhancing efficiencies & the continuity of existing operations 9 Refer to Slide Notes and Advisories Maximizing infrastructure utilization translating to stronger profitability & cash flow generation Faster cycle times across assets lowering costs & enhancing economic returns Leveraging unconventional workflow, improving well design & operating practices Improved base production performance exceeding internal forecasts CONTINUED OPERATIONAL MOMENTUM
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10 Refer to Slide Notes and Advisories $2.9 B $3.3 B $3.8 B US$50/bbl US$60/bbl US$70/bbl 2026 Funds Flow Sensitivity $2.0 – $2.1 Billion Crude Oil & Condensate NGLs Natural Gas 370 – 375 mboe/d 60% Liquids 40% Natural Gas Capital Budget Average Annual Production DISCIPLINED 2026 BUDGET 22% Growth vs. 2025 average production 380,000 boe/d Q4/26 production forecast 25% Conventional 156 (133.6 net) wells 75% Unconventional 98 (98.0 net) wells Production guidance includes 12,000 boe/d third party downtime in Q3/26 (3,000 boe/d annual impact)
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2026 FREE FUNDS FLOW 11 Focus on Total Shareholder Returns Target 10% – 15% Annually • Per Share Growth • Prioritizing share repurchases over production growth at current commodity prices • Permanently improves capital structure while maintaining low payout ratio • Capital flexibility with improvements in commodity prices • Base Dividend • Annual dividend of $0.73 per share fully funded at low commodity prices Balance Sheet Strength • Consistent focus on maintaining low leverage and balance sheet flexibility Refer to Slide Notes and Advisories 372,500 boe/d and $3.00/GJ AECO $3.3 B $2.1 B $0.9 B $0.3 B Funds Flow (US$60/bbl) Capital Budget Base Dividend Share Repurchases / Debt Reduction Total of $800 million of share repurchases and / or debt reduction at US$70/bbl WTI
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12 12 ASSET OVERVIEW Refer to Slide Notes and Advisories ✓ Premier multi-basin portfolio ✓ Diversified commodity mix optimizes returns ✓ Scale enhances operating profits ✓ Deep inventory of premium locations AB SK UNCONVENTIONAL Liquids rich, deep inventory CONVENTIONAL High netback, low decline ~10,500 Inventory Locations 55% Conventional 45% Unconventional
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UNCONVENTIONAL ASSET OVERVIEW Leveraging our deep technical expertise and historical success to drive improved economic returns 1,500,000 acres of Montney & Duvernay rights 4,700 Montney & Duvernay locations in inventory Duvernay Lands Montney Lands 200 km (125 miles) 200 km (125 miles) Unconventional Land Base Kaybob Gold Creek Karr Musreau Kakwa Lator Resthaven Refer to Slide Notes and Advisories 13 ~80% unbooked Significant future upside
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ALBERTA MONTNEY DRIVING FUTURE GROWTH Refer to Slide Notes and Advisories ~4,000 Inventory Locations T55 R21W5 Largest landholder in the Alberta Montney with ~1,000,000 acres 38% Oil/Condensate 29% Liquids Rich 33% Lean Gas 14 Township (6 miles x 6 miles)
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Refer to Slide Notes and Advisories R15W5 OPTIMIZING DUVERNAY DEVELOPMENT Largest Duvernay landholder with ~500,000 acres in the heart of the Duvernay at Kaybob T56 ~700 Inventory Locations 46% Liquids Rich 40% Oil/Condensate 14% Lean Gas 15 Township (6 miles x 6 miles)
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UNCONVENTIONAL INVENTORY 16 Refer to Slide Notes and Advisories. Assumes US$60/bbl WTI, $3.00/GJ AECO, and 1.39 USD/CAD. 4.72% Oil/Cond. Liquids Rich Lean Gas Musreau / Gold Creek / Kaybob Lator / Kakwa / Kaybob Resthaven / Kaybob DCE&T Costs ($mm) $10.0 $11.7 $12.3 IP90 (boe/d) (% liquids) 800 – 1,550 50% – 85% 1,000 – 2,000 35% – 65% 1,500 – 2,500 10% – 35% 2P Reserves (mboe) (% liquids) 600 – 1,300 45% – 75% 1,000 – 2,000 30% – 60% 1,500 – 2,700 10% – 30% Payout (years) 0.9 0.9 1.3 P/I Ratio (x) 1.0x 1.4x 1.2x IRR (%) >100% >100% 80% NPV (10% disc.) ($mm) $10.0 $15.9 $14.3 ~100 2,600 2,100 2026 Drills Unconventional PREMIUM INVENTORY Primary development within core areas across the Montney and Duvernay ADDITIONAL INVENTORY Future upside locations sensitive to natural gas prices Multi-Decade Inventory Life 16
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2nd largest conventional light oil producer in Canada Largest light oil producer in Saskatchewan History of asset optimization and inventory enhancement across portfolio Refer to Slide Notes and Advisories >3,000,000 acres Significant landholder across multiple, highly economic plays 5,800 locations Light oil development focused on continual enhancements 20 Billion Bbls OOIP EOR project potential 14 billion bbls OOIP CONVENTIONAL ASSETS Glauconite Cardium Viking Alberta Saskatchewan Shaunavon Bakken Frobisher Midale Cardium Cardium Charlie Lake Conv Montney 17
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CONVENTIONAL INVENTORY 18 Refer to Slide Notes and Advisories. Assumes US$60/bbl WTI, $3.00/GJ AECO, and 1.39 USD/CAD. 4.72% Alberta Saskatchewan Glauconite / Cardium Frobisher / Bakken DCE&T Costs ($mm) $4.9 $2.0 IP90 (boe/d) (% liquids) 270 – 965 50% – 90% 100 – 250 95% 2P Reserves (mboe) (% liquids) 350 – 1,000 45% – 80% 50 – 200 95% Payout (years) 0.9 1.0 P/I Ratio (x) 1.3x 1.0x IRR (%) >100% >100% NPV (10% disc.) ($mm) $6.2 $1.9 Multi-Decade Inventory Life ~155 ~2,900 ~2,900 2026 Drills Conventional PREMIUM INVENTORY Primary development targeting light oil assets in the Cardium, Charlie Lake, Conventional Montney, Frobisher, Glauconite and Viking Formations ADDITIONAL INVENTORY Future upside locations 18
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19 2.2 Billion Bbls 0.5 Billion Bbls 0.2 Billion Bbls 0.6 Billion Bbls 1.4 Billion Bbls Recovered To-Date Current Project Recoverable Brownfield Expansion Future Upside Significant Recovery Potential 2P Booked Recoverable Upside over 4x greater than 2P Reserves LARGE OOIP Refer to Slide Notes and Advisories East 3.1 Billion OOIP 14 Billion Bbls OOIP 35% Estimated Recovery Boundary Lake 0.8 Billion Bbls OOIP Central Alberta 1.5 Billion Bbls OOIP Southwest SK 6.2 Billion Bbls OOIP Weyburn 2.5 Billion Bbls OOIP East SK 3.1 Billion Bbls OOIP Alberta & Saskatchewan OOIP
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20 OPPORTUNITIES FOR IMPROVED RECOVERY Refer to Slide Notes and Advisories Area EOR Production Project Type EOR Project Total OOIP Est. Total Recovery Recovery To Date Risked Recovery Remaining Unrisked Recovery Remaining Project Upside(bbls/d) (Million bbls) (Million bbls) (Million bbls) (Million bbls) (Million bbls) AB Conv. 7,500 Waterflood 2,300 1,000 400 100 500 Expand waterflood into primary lands + EOR Southwest SK 19,000 Waterflood Polymer 6,200 1,700 900 150 650 Expand waterflood into primary lands + EOR East SK 11,000 Waterflood 3,100 1,200 300 150 750 Expand waterflood (remaining 2/3 resource) + EOR Weyburn 14,500 Waterflood CO2 2,500 1,000 600 300 100 Expand into non-unit lands + Frobisher TOTAL 52,000 14,100 4,900 2,200 700 2,000 Supports sustainable volume capture for decades to come
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21 DIVERSIFIED PORTFOLIO MAXIMIZES RETURNS Refer to Slide Notes and Advisories Allocating capital to the highest return projects depending on commodity prices 0% 25% 50% 75% 100%IP90 Percentage Liquids Unconventional Conventional
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STRONG CREDIT PROFILE $195 MM $300 MM $950 MM $450 MM 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Maturity Schedule Private Placement Notes Investment Grade Sr. Notes 3.90% 3.76% 4.72% 5.50% ✓ Investment-grade rating of BBB by DBRS ✓ Low effective cost of debt at 4% ✓ Target Net Debt / Funds Flow of 1.0x or less ✓ Ample liquidity of $1.5 billion Debt Composition 50% Fixed Interest Rate Debt 50% Variable Interest Rate Debt $3.4 B Net Debt Refer to Slide Notes and Advisories. Net debt and liquidity as at December 31st, 2025. 22
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23 23 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026e Net Debt / Funds Flow Ratio Avg. Net Debt / Funds Flow = 1.5x Refer to Slide Notes and Advisories PRUDENT BALANCE SHEET MANAGEMENT Proven leverage discipline through commodity price cycles WTI (US$/bbl) $97.97 $93.00 $48.80 $43.32 $50.95 $64.77 $57.03 $39.40 $67.92 $94.23 $77.62 $75.57 $64.81 $60.00
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24 24 RISK MANAGEMENT Downside protection to support dividend and maintain production 26% 24% 10% 1H '26 2H '26 2027 Oil Hedges (% of Production Hedged) Swaps Collars 30% 28% 13% 1H '26 2H '26 2027 Natural Gas Hedges (% of Production Hedged) Swaps Collars Target 25% – 35% hedged Refer to Slide Notes and Advisories $84.57 $84.89 $70.69Floor Price (C$/bbl) $3.79 $3.73 $2.85Floor Price (C$/GJ)
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NATURAL GAS PRICE EXPOSURE 25 Refer to Slide Notes and Advisories 29% 25% 49% 25% 22% 30% 20% 2026 Target Price Diversification Fixed AECO AECO U.S. & Other Markets LNG Long term price diversification target to minimize market risk New long-term agreements add exposure to European TTF and Henry Hub pricing Centrica 50,000 mmbtu/d 10 Year @ TTF Pricing Other 35,000 mmbtu/d 10 Year @ HH Pricing
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CRUDE OIL PRICE EXPOSURE 26 Refer to Slide Notes and Advisories 63% 25% 12% Condensate ✓ Montney ✓ Duvernay Medium Oil ✓ Southwest Saskatchewan Light Oil ✓ Saskatchewan ✓ Montney ✓ Duvernay 88% of production exposed to attractive light oil and condensate prices
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ASSET POTENTIAL 27 2026 Guidance Near-term Productive Capacity Future Growth Projects (Unconventional) Future Upside Potential (Conventional) 372,500 boe/d +90,000 boe/d Near-term availability from: • Utilizing available capacity • Debottlenecking efforts • Lator Phase 1 Significant productive capacity & long-term growth potential +325,000 boe/d Near-term and future productive capacity provides flexibility to respond to market conditions Commodity optionality within future project list Future growth potential from: • Lator Phase 2 • Gold Creek/Karr Expansion • Resthaven • Kakwa Expansion Montney Duvernay Alberta Conv. Saskatchewan Conv. Future upside potential from: • Secondary & Tertiary expansion opportunities • Increased recovery factor of current EOR assets • Technology enhancements in open hole multi-lateral & monobore drilling Refer to Slide Notes and Advisories
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GROWTH OPTIONALITY 28 2026 2030 Stay Flat 3% Annual Growth 5% Annual Growth 450,000 boe/d 372,500 boe/d 420,000 boe/d $14.5 B $17.0 B $20.0 B US$50/bbl US$60/bbl US$70/bbl 5 Year Cumulative Funds Flow Stay Flat 3% Growth 5% Growth $1.0 B $1.5 B $1.9 B US$50/bbl US$60/bbl US$70/bbl Run-Rate Free Funds Flow 420,000 boe/d 420,000 boe/d 420,000 boe/d Refer to Slide Notes and Advisories Illustrative outcomes under different capital allocation scenarios and commodity price environments
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29 29 Refer to Slide Notes and Advisories Convert high-quality inventory into sustainable free funds flow & superior long-term shareholder returns BUILT TO PROVIDE DURABLE RETURNS THROUGH THE PRICE CYCLES Depth & Quality of Opportunity Premier multi-basin inventory providing scale, flexibility & long-term sustainability Technical Excellence & Top-Tier Operating Performance Integrated subsurface, drilling, completion & production optimization delivering repeatable capital efficiency Durable Free Funds Flow Low decline, capital efficient assets support reliable long-term free funds flow generation Capital Discipline & Returns Investment-grade balance sheet & capital allocation framework supporting annual shareholder returns Our Commitment:
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30 ADDITIONAL INFORMATION
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2026 GUIDANCE 31 Refer to Slide Notes and Advisories Production Crude oil and condensate (bbls/d) 180,000 – 182,000 NGLs (bbls/d) 43,500 – 44,500 Natural gas (mcf/d) 879,000 – 891,000 Total production (boe/d) 370,000 – 375,000 Capital Expenditures $2.0 – $2.1 Billion Expenses ($/boe) Royalties 12% – 13% Operating $12.25 – $12.75 Transportation $3.25 – $3.50 G&A expense $1.05 Current income tax expense as a % of funds flow 3% – 5% $50 MM $20 MM $45 MM $0 $10 $20 $30 $40 $50 $60 +/- US$1.00/bbl WTI +/- $0.10/GJ AECO +/- $0.01 FX Change in Funds Flow 2026 Funds Flow Sensitivity$MM
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32 32 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026e $ million - 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026e Boe/d - 500,000 1,000,000 1,500,000 2,000,000 2,500,000 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Mboe 11% CAGR per share11% CAGR per share 11% CAGR per share Refer to Slide Notes and Advisories 2P ReservesProductionFunds Flow MANAGEMENT TRACK RECORD OF EXECUTION Organic growth enhanced by strategic acquisitions
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33 33 DISCIPLINED RETURN OF CAPITAL TO SHAREHOLDERS $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 $/share Cumulative Dividend & NCIB ($/sh) $0.61 $7.73 $935 million Share repurchases completed (May 2017 – Dec. 2025) $3.0 billion Total dividends paid ($6.24/share) (Jan. 2013 – Dec. 2025) Refer to Slide Notes and Advisories
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TSX: WCP wcap.ca InvestorRelations@wcap.ca February 23, 2026
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35 SLIDE NOTES Slide 2 1. Market Capitalization and Enterprise Value calculated based on fully diluted common shares outstanding as at December 31st, 2025, a share price of $13.50 and December 31st, 2025 net debt of $3.4 billion. 2. Market Capitalization and Enterprise Value are supplementary financial measures. See Specified Financial Measures in the Advisories. 3. Net debt and funds flow are capital management measures. See Specified Financial Measures in the Advisories. 4. Net debt to funds flow is annualized net debt to funds flow, which is a supplementary financial measure. See Specified Financial Measures in the Advisories. 5. See Oil and Gas Advisory in the Advisories for additional information on production. 6. Expenditures on property, plant and equipment also referred to as "Capital Expenditures" or "Capital Budget" or "Capital Spending", "Capital" or "Capital Investments". Slide3 1. Total shareholder return is a supplementary financial measure. See Specified Financial Measures in the Advisories. 2. Free funds flow is a non-GAAP financial measure. See Specified Financial Measures in the Advisories. 3. Net debt and funds flow are capital management measures. See Specified Financial Measures in the Advisories. 4. Net debt to funds flow is annualized net debt to funds flow, which is a supplementary financial measure. See Specified Financial Measures in the Advisories. Slide 4 1. See Oil and Gas Advisory in the Advisories for additional information on production. Slide 5 1. Reserves for 2025 are based on McDaniel & Associates Consultants Ltd.’s ("McDaniel") reserves evaluation reports effective December 31, 2025, in accordance with NI 51-101 and the COGE Handbook. 1. See Oil and Gas Advisory in the Advisories for additional information on production replacement, reserves and recycle ratio. 2. PDP is defined as proved developed producing reserves, 1P is defined as total proved reserves and 2P is defined as total proved plus probable reserves. 3. For 2P reserves, the constituent product types and their respective quantities may be found in the February 23, 2026 press release that can be accessed on Whitecap’s website (wcap.ca) and will be included in the Annual Information Form for 2025, copies of which may be accessed through the Company's profile on the SEDAR+ website (sedarplus.ca). Slide 6 1. Total shareholder return is a supplementary financial measure. See Specified Financial Measures in the Advisories. 2. Net debt and funds flow are capital management measures. See Specified Financial Measures in the Advisories. 3. Net debt to funds flow is a supplementary financial measure. See Specified Financial Measures in the Advisories. 4. See Oil and Gas Advisory in the Advisories for additional information on reserves, RLI and drilling locations. 5. Reserves for 2025 are based on McDaniel reserves evaluation reports effective December 31, 2025, in accordance with NI 51- 101 and the COGE Handbook. 6. PDP is defined as proved developed producing reserves, 1P is defined as total proved reserves, 2P is defined as total proved plus probable reserves. Slide 7 1. Net debt and funds flow are capital management measures. See Specified Financial Measures in the Advisories. 2. Net debt to funds flow and payout ratio are supplementary financial measures. See Specified Financial Measures in the Advisories. 3. Production per share is the Company's total crude oil, NGL and natural gas production volumes for the applicable period divided by the weighted average number of diluted shares outstanding for the applicable period. Production per share growth is determined in comparison to the applicable comparative period. Slide 8 1. Free funds flow is a non-GAAP financial measure. See Specified Financial Measures in the Advisories. Slide 10 1. Funds flow is a capital management measure. See Specified Financial Measures in the Advisories. 2. Funds flow sensitivity assumes $3.00/GJ AECO. 3. Expenditures on property, plant and equipment also referred to as "Capital Expenditures" or "Capital Budget" or "Capital Spending", "Capital" or "Capital Investments". 4. See Oil and Gas Advisory in the Advisories for additional information on production. Slide 11 1. Funds flow is a capital management measure. See Specified Financial Measures in the Advisories. 2. Expenditures on property, plant and equipment also referred to as "Capital Expenditures" or "Capital Budget" or "Capital Spending", "Capital" or "Capital Investments". 3. Free funds flow is a non-GAAP financial measure. See Specified Financial Measures in the Advisories. 4. Total shareholder return is a supplementary financial measure. See Specified Financial Measures in the Advisories. Slide 12 1. See Oil and Gas Advisory in the Advisories for additional information on production and drilling locations. 2. Inventory depicted is year end 2025 gross locations. 3. See Production, Initial Production Rates & Product Type Information in the Advisories. Slide 13 - 15 1. See Oil and Gas Advisory in the Advisories for additional information on drilling locations. 2. Inventory depicted is year end 2025 gross locations.
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36 SLIDE NOTES Slide 16 1. See Oil and Gas Advisory in the Advisories for additional information on drilling locations, DCE&T costs, payout, profit to investment (P/I), IRR (Rate of Return) and reserves. 2. See Specified Financial Measures in the Advisories for additional information on NPV. 3. See Production, Initial Production Rates & Product Type Information in the Advisories. 4. Inventory depicted is year end 2025 gross locations. 5. Premium inventory is defined as 1.5 year payout and less at US$75/bbl WTI and $3/GJ AECO. 6. Reserves for 2025 are based on McDaniel reserves evaluation reports effective December 31, 2025, in accordance with NI 51-101 and the COGE Handbook. Slide 17 1. See Oil and Gas Advisory in the Advisories for additional information on drilling locations. 2. Inventory depicted is year end 2025 gross locations. 3. Gross Original Oil in Place ("OOIP") is based on internal estimates. Whitecap has an average working interest of 81% on the assets. See Oil and Gas Advisory in the Advisories for additional information on OOIP. Slide 18 1. See Oil and Gas Advisory in the Advisories for additional information on drilling locations, DCE&T costs, payout, profit to investment (P/I), IRR (Rate of Return) and reserves. 2. See Specified Financial Measures in the Advisories for additional information on NPV. 3. See Production, Initial Production Rates & Product Type Information in the Advisories. 4. Inventory depicted is year end 2025 gross locations. 5. Premium inventory is defined as 1.5 year payout and less at US$75/bbl WTI and $3/GJ AECO. 6. Reserves for 2025 are based on McDaniel reserves evaluation reports effective December 31, 2025, in accordance with NI 51-101 and the COGE Handbook. Slide 19 1. Gross OOIP is based on internal estimates. Whitecap has an average working interest of 81% on the assets. See Oil and Gas Advisory in the Advisories for additional information on OOIP. 2. 2P is total proved plus probable reserves. 3. See Specified Financial Measures in the Advisories for additional information on NPV. 4. Reserves for 2025 are based on McDaniel reserves evaluation reports effective December 31, 2025, in accordance with NI 51-101 and the COGE Handbook. Slide 20 1. See Production, Initial Production Rates & Product Type Information in the Advisories. 2. Gross OOIP is based on internal estimates. Whitecap has an average working interest of 81% on the assets. See Oil and Gas Advisory in the Advisories for additional information on OOIP. 3. Risked recovery remaining is based on year end 2025 reserves plus internal project estimates. 4. Unrisked recovery remaining is based on internally estimated percentage recoverable beyond current project forecasts. Slide 21 1. See Production, Initial Production Rates & Product Type Information in the Advisories. Slide 22 1. Net debt and funds flow are capital management measures. See Specified Financial Measures in the Advisories. 2. Net debt to funds flow is a supplementary financial measure. See Specified Financial Measures in the Advisories. 3. Variable interest rate debt includes working capital. Slide 23 1. Net debt and funds flow are capital management measures. See Specified Financial Measures in the Advisories. 2. Net debt to funds flow is a supplementary financial measure. See Specified Financial Measures in the Advisories. 3. Adjustments have been made to the reported funds flow figure for 2014 and 2017 due to material acquisitions being completed in the fourth quarter. 4. 2025 net debt to funds flow is annualized net debt to funds flow which is a supplementary financial measure. See Specified Financial Measures in the Advisories. Slide 24 1. Hedge positions current to February 20th, 2026. 2. Percent of net royalty volumes hedged are based on Whitecap average production of 372,500 boe/d for 2026 and 2027. 3. Please refer to Whitecap’s website at www.wcap.ca/investors/financial-reports for additional hedging disclosure. Slide 25 1. Natural gas financial exposure based on current production volumes. 2. Other markets includes Dawn, Henry Hub, Malin and power markets. Slide 26 1. Crude oil financial exposure based on current production volumes. Slide 27 1. See Oil and Gas Advisory in the Advisories for additional information on production. Slide 28 1. See Oil and Gas Advisory in the Advisories for additional information on production. 2. Funds flow is a capital management measure. See Specified Financial Measures in the Advisories. 3. "Free Funds Flow" is a non-GAAP financial measure. See Specified Financial Measures in the Advisories. 4. Assumes $3.00/GJ for each scenario and USD/CAD rates of $1.43, $1.39 and $1.35 at US$50/bbl, US$60/bbl and US$70/bbl, respectively. Slide 29 1. "Free Funds Flow" is a non-GAAP financial measure. See Specified Financial Measures in the Advisories.
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37 SLIDE NOTES Slide 31 1. See Oil and Gas Advisory in the Advisories for additional information on production. 2. Expenditures on property, plant and equipment also referred to as "Capital Expenditures" or "Capital Budget" or "Capital Spending", "Capital" or "Capital Investments". 3. Funds flow is a capital management measure. See Specified Financial Measures in the Advisories. Slide 32 1. Funds flow is a capital management measure. See Specified Financial Measures in the Advisories. 2. See Oil and Gas Advisory in the Advisories for additional information on production. 3. Reserves for 2010-2025 are based on McDaniel reserves evaluation reports effective December 31 of the respective year in accordance with NI 51-101 and the COGE Handbook. 4. CAGR is the compound annual growth rate representing the measure of annual growth over multiple time periods. 5. 2P is defined as total proved plus probable reserves. Slide 33 1. NCIB refers to our normal course issuer bid. 2. Total dividends per share and cumulative dividends plus NCIB are based on the weighted average basic shares in the year the dividend was paid or shares repurchased.
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38 the Alberta Montney will drive future growth; that we are the 2nd largest conventional light oil producer in Canada; our estimate of gross conventional OOIP and EOR project potential (including split by area); our belief that there is significant resource recovery upside potential on our conventional assets; our estimate for resource recovery (including as compared to our 2P reserves) including our forecasted split by current projects, brownfield expansions and future upside (both total and split by risked and unrisked); our belief that opportunities for improved recovery support sustainable resource capture for decades to come; our belief as to the forecasted project upside development by area; our belief that our diversified portfolio maximizes returns; our forecast year end 2026 net debt, including the underlying assumptions; our belief that our hedging program provides downside protection to support the dividend and maintain production; our hedged targets; our forecasted near-term productive capacity by area, future growth projects (unconventional) and future upside potential (conventional); and our illustrative forecasts of 5 year production growth, cumulative funds flow and run-rate free funds flow under different capital allocation scenarios and commodity price environments; our funds flow sensitivity forecast for changes in WTI, AECO and FX; our natural gas price diversification targets; and estimated compound annual growth rate for funds flow per share and production per share. The forward-looking information is based on certain key expectations and assumptions made by our management, including: the dura tion and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the ta riffs 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) i mposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil a nd natural gas; that we will continue to conduct our operations in a manner consistent with past operations except as specifically noted here in (and for greater certainty, the forward-looking information contained herein excludes the potential impact of any acquisitions or disposi tions that we may complete in the future); the general continuance or improvement in current industry conditions; the continuance of exi sting (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; expectations and assumptions conc erning prevailing and forecast commodity prices, exchange rates, interest rates, inflation rates, applicable royalty rates and tax l aws, including the assumptions specifically set forth herein; the ability of OPEC+ nations and other major producers of crude oil to adjust crud e oil production levels and thereby manage world crude oil prices; the impact (and the duration thereof) of the ongoing military ac tions in the Middle East and between Russia and Ukraine and related sanctions on crude oil, NGLs and natural gas prices; the impact of cur rent and forecast exchanges rates, inflation rates and/or interest rates on the North American and world economies and the correspondi ng impact on our costs, our profitability, and on crude oil, NGLs and natural gas prices; future production rates and estimates of oper ating costs and development capital, including as specifically set forth herein; performance of existing and future wells; reserves volumes and net present values thereof; anticipated timing and results of capital expenditures/development capital, including as specifically set for th herein; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the timing and costs of pipeline, storage and facility construction and ex pansion; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; future dividend levels and share repurchase levels; the impact of increasing competition; ability to efficiently integrate assets and employe es acquired through acquisitions or asset exchange transactions; ability to market oil and natural gas successfully; our ability to acces s capital and the cost and terms thereof; that we will not be forced to shut -in production due to weather events such as wildfires, floods, drough ts or extreme hot or cold temperatures; and that we will be successful in defending against previously disclosed and ongoing reasse ssments received from the Canada Revenue Agency and assessments received from the Alberta Tax and Revenue Administration. In addition, this presentation contains various assumptions regarding future commodity prices, exchange rates, capital expenditures, net debt levels, free cash flow levels and other matters that are located proximate to the aforementioned forward-looking information. ADVISORIES Special Note Regarding Forward-Looking Statements and Forward-Looking Information This presentation contains forward-looking statements and forward-looking information (collectively, "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as "anticipate", "believe", "continue", "trend", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend", "estimate", "potential", or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future, including statements about our strategy, plans, focus, objectives, priorities, position and our value creation its components. In particular, and without limiting the generality of the foregoing, this presentation contains forward-looking information with respect to: Whitecap's focus, growth, plans, commitments, priorities and strategies and the benefits to be derived therefrom; the 2026 forecast for annualized production (including by product type and area), funds flow (including on a per share basis), free funds flow, capital budget, royalties, operating cost, transportation cost, G&A expense and current income tax expense as a percentage of funds flow guidance; that Whitecap is the seventh largest Canadian oil and gas producer and the fifth largest Canadian natural gas producer, based on market capitalization and on 2026 forecast production for the peer group and Whitecap; our belief that our exposure to oil/condensate, liquids rich and lean gas assets will maximize returns through commodity cycles; our belief that conservative reserve booking supports significant future inventory upside; our believe that we have a long duration reserve base; our belief that we have a low cost structure; our belief with respect to the benefits of owning Whitecap shares; our forecasted drilling locations split by conventional and unconventional (including Montney and Duvernay) and also split by premium and additional inventory; that we are the largest Alberta Montney and Duvernay landholder; that we are the largest light oil producer in Saskatchewan; anticipated reserve life index of the total proved and probable reserves; our target annual total shareholder return and underlying assumptions; our belief that we will run a fully funded model; our belief that share repurchases provide permanent improvement to capital structure; our target of 1.0 times net debt to funds flow ratio; our target of 3% - 5% per share growth per annum dependent on commodity prices; our plan to increase production growth as returns increase; our target payout ratio of 20% - 25%; our plan to grow the base dividend with the business longer term; our belief that low leverage, long inventory life and scale allows counter-cyclical investing through commodity cycles; our planned allocation of annual free funds flow at various commodity prices; our belief that maximizing infrastructure utilization will translate into stronger profitability and cash flow generation; our belief that faster cycle times across assets is lowering costs and enhancing economic returns; our belief that optimizing drilling programs is enhancing efficiencies and the continuity of existing operations; our belief that leveraging the unconventional workflow will improve well design and operating practices; our belief that improved base production performance is exceeding internal forecasts; our forecasts for the allocation of our 2026 capital program to our unconventional and conventional assets, including the expected wells drilled and production in total and by region; our expected production growth in 2026; our forecasted 2026 production profile and underlying assumptions, including in total and by region; our belief that our 2026 budget is disciplined; our plan to prioritize share repurchases over production growth at current commodity prices; our belief that share repurchases provide permanent improvement to capital structure while maintaining low payout ratio; our belief that we have capital flexibility with improvements in commodity prices; our consistent focus on maintaining low leverage and balance sheet flexibility; our anticipated annual dividend; our belief that the annual dividend of $0.73 per share is fully funded at low commodity prices; our belief that we have a premier multi-basin portfolio, that our diversified commodity mix optimizes returns, that scale enhances operating profits and that we have a deep inventory of premium locations; relevant economic outputs for our unconventional and conventional assets; our forecasted 2026 drills for unconventional and conventional assets; that our unconventional and conventional inventory represents multi-decade inventory life; that Whitecap is the largest landholder at Kaybob in the heart of the Duvernay; that Whitecap is the largest landholder in the Alberta Montney;
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39 forward-looking information will transpire or occur, or if any of them do so, what benefits that we will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on our future operations and such information may not be appropriate for other purposes. Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR+ website at sedarplus.ca In addition, statements relating to "reserves" are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. The reserve estimates of Whitecap's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. These forward-looking statements are made as of the date of this presentation and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. This presentation contains future-oriented financial information and financial outlook information (collectively, "FOFI") about: our forecast 2026 capital expenditures, including the allocation to the unconventional and conventional divisions; our forecast of annualized production and average daily production for the fourth quarter of 2026, including by product type and region; our net debt to annualized funds flow ratio of 1.0 times; our forecast for funds flow of $3.3 billion for 2026; the amount of our annual base dividend; the funds flow sensitivity to changes in WTI, a AECO and FX; the forecast for capital investments, funds flow, dividends and share repurchases and / or dividends at US$60/bbl WTI and US$70/bbl WTI and $3.00/GJ AECO; the forecast of average daily production from near-term productive capacity, future growth projects (unconventional) and future upside potential (conventional); the forecast for 5 year production, cumulative funds flow and run-rate free funds flow at US$50/bbl WTI, US$60/bbl WTI and US$70/bbl WTI and $3.00/GJ AECO; the single well economics of certain assets including drill, complete, equip and tie-in costs and NPV (10%) at US$60/bbl WTI and US$70/bbl WTI and $3.00/GJ AECO; and our forecasts for commodity prices and the USD/CAD exchange rate all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above slides all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in this document. The actual results of operations of Whitecap and the resulting financial results will likely vary from the amounts set forth herein and such variation may be material. Whitecap and its management team believe that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Whitecap undertakes no obligation to update such FOFI. FOFI contained in this presentation was made as of the date of this presentation and was provided for the purpose of providing further information about Whitecap's anticipated future business operations. Readers are cautioned that the FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. Additionally, readers are advised that historical results, growth, acquisitions and dispositions described in this presentation may not be reflective of future results, growth, acquisitions and dispositions with respect to Whitecap. ADVISORIES Special Note Regarding Forward-Looking Statements and Forward-Looking Information (continued) Although we believe that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Whitecap can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. These include, but are not limited to: the risk that the funds that we ultimately return to shareholders through dividends and/or share repurchases is less than currently anticipated and/or is delayed, whether due to the risks identified herein or otherwise; the risk that any of our material assumptions prove to be materially inaccurate, including our 2026 forecasts (including for production levels, capital expenditure levels, commodity prices and exchange rates); 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 Company including by decreasing demand for (and the price of) oil and natural gas, disrupting supply chains, increasing costs, causing volatility in global financial markets, and limiting access to financing; the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, including the risk that weather events such as wildfires, flooding, droughts or extreme hot or cold temperatures forces us to shut-in production or otherwise adversely affects our operations; pandemics and epidemics; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; risks associated with increasing costs, whether due to elevated inflation rates, elevated interest rates, supply chain disruptions or other factors; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; inflation rate fluctuations; marketing and transportation risks; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; the risk that going forward we may be unable to access sufficient capital from internal and external sources on acceptable terms or at all; failure to obtain required regulatory and other approvals; reliance on third parties and pipeline systems; changes in legislation, including but not limited to tax laws, tariffs, import or export restrictions or prohibitions, production curtailment, royalties and environmental (including emissions and "greenwashing") regulations; the risk that we do not successfully defend against previously disclosed and ongoing reassessments received from the Canada Revenue Agency and assessments received from the Alberta Tax and Revenue Administration and are required to pay additional taxes, interest and penalties as a result; and the risk that the amount of future cash dividends paid by us and/or shares repurchased for cancellation by us (including pursuant to our normal course issuer bid ("NCIB")), if any, will be subject to the discretion of our Board of Directors and may vary depending on a variety of factors and conditions existing from time to time, including, among other things, fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates, contractual restrictions contained in our debt agreements, and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends and/or the repurchase of shares (including pursuant to the NCIB) – depending on these and various other factors as disclosed herein or otherwise, many of which will be beyond our control, our dividend policy and/or share buyback policy and, as a result, future cash dividends and/or share buybacks (including pursuant to the NCIB), could be reduced or suspended entirely. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the
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40 "Acquisition capital" is a non-GAAP financial measure used in the determination of FD&A costs, which is a non-GAAP ratio. The most directly comparable GAAP measure to acquisition capital is expenditures on corporate acquisitions, net of cash acquired, and expenditures on property acquisitions. For property acquisitions and dispositions, acquisition capital is the net purchase price of assets acquired (disposed). For corporate acquisitions, it is the purchase price (cash and/or shares plus assumed bank debt, if applicable) including any estimated working capital surplus or deficit rather than the amounts allocated to property, plant and equipment ("PP&E") for accounting purposes. "DCE&T costs" includes all direct, on-lease costs of a typical well under pad development, including drill, completion, equip and tie-in and excludes ancillary costs such as lease construction, area trunk lines and processing facilities, water infrastructure and later-life artificial lift, that are carried separately on a case by case basis. "Development capital" is a non-GAAP financial measure used in the determination of FD&A costs, which is a non-GAAP ratio. The most directly comparable GAAP measure to development capital is expenditures on property, plant, and equipment. Development capital means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital excludes corporate and capitalized general and administrative expenses. "F&D costs" are calculated as the sum of development capital plus the change in FDC for the period when appropriate, divided by the change in reserves that are characterized as development for the period. Development capital is a non -GAAP financial measure used as a component of F&D costs. Management uses F&D costs as a measure of capital efficiency for organic reserves development. "FD&A costs" are calculated as the sum of development capital plus acquisition capital plus the change in future development costs (being the best estimate of the capital cost to develop and produce reserves) for the period when appropriate, divided by the change in total reserves, other than from production, for the period. Development capital and acquisition capital are non -GAAP financial measures used as components of FD&A costs. Management uses FD&A costs as a measure of capital efficiency for organic and acquired reserves development. "IRR" is the discount rate that is applied to the forecasted operating income of a well such that it equates to the DCE&T Costs of a well. "Payout" is calculated by the time period for the operating netback of a well to equate to the individual cost of the well. Management uses payout as a measure of capital efficiency of a well to make capital allocation decisions. "Production replacement ratio" or "production replacement" is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. "Profit to investment ratio" is calculated by dividing the NPV of a well by the individual well cost. NPV is a supplementary financial measure. Management uses profit to investment ratio to make capital allocation decisions. ADVISORIES Oil and Gas Advisory Reserves All reserve references in this presentation are "Company share reserves". Company share reserves are our total working interest reserves before the deduction of any royalties and without including any royalty interests payable to the Company. The proved and probable reserves disclosed in this presentation are derived from McDaniel & Associates Consultants Ltd.'s reserves evaluation effective December 31, 2025, which were each evaluated or audited in accordance with the COGE Handbook (as defined below). See the annual information form of Whitecap in respect of the financial year ended December 31, 2025 dated February 23, 2026 for the applicable pricing forecasts. It should not be assumed that the present worth of estimated future amounts presented represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of the crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. Certain terms used herein but not defined are in National Instrument 51-101 ("NI 51-101"), CSA Staff Notice 51-324 – Revised Glossary to NI 51-101 Standards for Disclosure for Oil and Gas Activities ("CSA Staff Notice 51-324") and/or the Canadian Oil and Gas Evaluation ("COGE") Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGE Handbook, as the case may be. OOIP Original Oil-In-Place ("OOIP") contained herein is equivalent to Total Oil Initially-In-Place ("TOIIP") and has been estimated as of December 31, 2025. TOIIP, as defined in the COGE Handbook, is that quantity of oil that is estimated to exist in naturally occurring accumulations. It includes that quantity of oil that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TOIIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of the TOIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TOIIP will never be recovered. "Decline rate" is the reduction in the rate of production from one period to the next, expressed on an annual basis. Management of Whitecap uses decline rate to assess future productivity of Whitecap's and the company's assets. This presentation contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "acquisition capital", "DCE&T Cost", "development capital", "F&D costs", "FD&A costs", "IRR", "payout", "production replacement ratio", "profit to investment ratio", "recycle ratio" and "RLI". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.
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41 ADVISORIES "Recycle ratio" is calculated by dividing operating netback per boe by F&D costs or FD&A costs for the year. Operating netback per boe is a non-GAAP ratio that uses operating netback, a non-GAAP financial measure, as a component. Development capital and acquisition capital, both non-GAAP financial measures, are used as components of FD&A costs. Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated. "Reserve life index" or "RLI" is calculated as total Company share reserves as at December 31, 2024 divided by 370,000 boe/d. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare our operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be relied upon for investment or other purposes. Type Curve This presentation references certain type curves and well economics. Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling in certain areas and for determining the success of the performance of wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells and such type curves do not reflect the type curves used by Whitecap's independent qualified reserves evaluator in estimating Whitecap's reserves volumes. The type curves can differ as a result of varying horizontal well length, stage count and stage spacing. The type curves represent the average type curves expected. Barrel of Oil Equivalency "Boe" means barrel of oil equivalent. All boe conversions in this presentation are derived by converting gas to oil at the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl : 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value. Drilling Locations This presentation discloses drilling inventory in two categories: (i) booked locations (proved and probable); and (ii) unbooked locations. Booked locations represent the summation of proved and probable locations, which are derived from McDaniel's reserves evaluation effective December 31, 2025 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations consist of drilling locations that have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all of these drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. The following table provides a breakdown of the current Whitecap gross (net) drilling locations included in this presentation: Gross (Net) Total Drilling Inventory Proved Locations Probable Locations Unbooked Locations Montney & Duvernay 4,669 (4,415) 717 (700) 263 (257) 3,689 (3,458) Conventional 5,812 (5,139) 1,539 (1,386) 469 (424) 3,804 (3,329)
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42 ADVISORIES Light and Medium Oil (bbls/d) Tight Oil / Condensate (bbls/d) NGLs (bbls/d) Shale Gas (Mcf/d) Conventional Natural Gas (Mcf/d) Total (boe/d) Q4 2026 90,000 93,500 45,000 749,000 160,000 380,000 2026 / Stay Flat 90,000 91,000 44,000 720,000 165,000 372,500 3% Growth 90,000 108,000 52,000 855,000 165,000 420,000 5% Growth 90,000 115,000 60,000 945,000 165,000 450,000 Production, Initial Production Rates & Product Type Information References to petroleum, crude oil , NGLs, natural gas and average daily production in this presentation refer to the light and medium crude oil, tight crude oil, conventional natural gas, shale gas and NGLs product types, as applicable, as defined in NI 51- 101, except as noted below. NI 51-101 includes condensate within the NGLs product type. Whitecap has disclosed condensate as combined with crude oil and separately from other natural gas liquids since the price of condensate as compared to other natural gas liquids is currently significantly higher and Whitecap believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom. Crude oil therefore refers to light oil, medium oil, tight oil and condensate. NGLs refers to ethane, propane, butane and pentane combined. Natural gas refers to conventional natural gas and shale gas combined. Any reference in this presentation to initial production rates (IP(90)) are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Whitecap. The Company's average production disclosed in this presentation consist of the following product types, as defined in NI 51 -101 (other than as noted above with respect to condensate) and using a conversion ratio of 1 Bbl : 6 Mcf where applicable: Specified Financial Measures This presentation includes various specified financial measures, including non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as further described herein. These financial measures are not standardized financial measures under International Financial Reporting Standards ("IFRS Accounting Standards" or, alternatively, "GAAP") and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other companies. "Enterprise value" is a supplementary financial measure and is calculated as market capitalization plus net debt. Management believes that enterprise value provides a useful measure of the market value of the combined company's debt and equity. Market capitalization is a supplementary financial measure. "Free funds flow" is a non-GAAP financial measure calculated as funds flow less expenditures on property, plant and equipment ("PP&E"). Management believes that free funds flow provides a useful measure of the combined company's ability to increase returns to shareholders and to grow the combined company's business. Free funds flow is not a standardized financial measure under IFRS Accounting Standards and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. The most directly comparable financial measure to free funds flow disclosed in the combined company's primary financial statements is cash flow from operating activities. Refer to the "Cash Flow from Operating Activities, Funds Flow and Free Funds Flow" section of Whitecap's management's discussion and analysis for the year ended December 31, 2025 which is incorporated herein by reference, and available on SEDAR+ at sedarplus.ca. "Funds flow", "funds flow basic ($/share)" and "funds flow diluted ($/share)" are capital management measures and are key measures of operating performance as they demonstrate the combined company's ability to generate the cash necessary to pay dividends, repay debt, make capital investments, and/or to repurchase common shares under Whitecap's normal course issuer bid. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds flow, funds flow basic ($/share) and funds flow diluted ($/share) provide useful measures of the combined company's ability to generate cash that are not subject to short-term movements in non-cash operating working capital. Whitecap reports funds flow in total and on a per share basis (basic and diluted), which is calculated by dividing funds flow by the weighted average number of basic shares and weighted average number of diluted shares outstanding for the relevant period. Refer to the "Cash Flow from Operating Activities, Funds Flow and Free Funds Flow" section of Whitecap's management's discussion and analysis for the year ended December 31, 2025 which is incorporated herein by reference, and available on SEDAR+ at sedarplus.ca.
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43 ADVISORIES "Payout ratio" is a supplementary financial measure calculated as dividends paid or declared divided by funds flow. Management believes that payout ratio provides a useful measure of Whitecap's dividend policy, as a percentage of the amount of funds flow. "Total Shareholder Return" is a supplementary financial measure calculated as the sum of the annual base dividend and NCIB yield, per share production growth, and change in net debt expressed on a per share basis. Management believes that total shareholder return provides a useful measure of the return characteristics of various capital allocation decisions. See the related sections in Whitecap's management's discussion and analysis for the year ended December 31, 2025, which is incorporated herein by reference, and available on SEDAR+ at sedarplus.ca for free funds flow, net debt and operating netback reconciliation tables. Per Share Amounts Per share amounts noted in this presentation are based on fully diluted shares outstanding unless noted otherwise. Dividends Whitecap's future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on Whitecap's shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of Whitecap's Board of Directors and may depend on a variety of factors, including, without limitation, Whitecap's business performance, financial condition, financial requirements, growth plans, expected capital requirements, tariffs affecting the export of crude oil and natural gas to the U.S., and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Whitecap under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of Whitecap's Board of Directors. There can be no assurance that Whitecap will pay dividends in the future. Specified Financial Measures (continued) "Market capitalization" is a supplementary financial measure and is calculated as the current share price multiplied by the number of shares outstanding at the end of the period. Management believes that market capitalization provides a useful measure of the market value of Whitecap's equity. "Net Debt" is a capital management measure that management considers to be key to assessing the combined company's liquidity. Refer to Note (2) in the "Summary of Quarterly Results" section of Whitecap's management's discussion and analysis for the year ended December 31, 2025 which is incorporated herein by reference, and available on SEDAR+ at sedarplus.ca. "Net Debt to annualized funds flow ratio" is a supplementary financial measure determined by dividing net debt for the applicable period by annualized funds flow. Net debt to annualized funds flow is not a standardized measure and, therefore, may not be comparable with the calculation of similar measures by other entities. "Net Debt to Funds Flow" is a supplementary financial measure determined by dividing net debt by funds flow. Net debt to funds flow is not a standardized measure and, therefore, may not be comparable with the calculation of similar measures by other entities. "NPV" (10% discount rate) is a supplementary financial measure comprised of the before tax NPV for 2P reserves, discounted at 10%, as determined in accordance with NI 51-101. "Operating netback" is a non-GAAP financial measure determined by adding marketing revenues and processing & other income, deducting realized losses on commodity risk management contracts or adding realized gains on commodity risk management contracts and deducting tariffs, royalties, operating expenses, transportation expenses and marketing expenses from petroleum and natural gas revenues. The most directly comparable financial measure to operating netback disclosed in the Company's primary financial statements is petroleum and natural gas sales. Operating netback is a measure used in operational and capital allocation decisions. Operating netback is not a standardized financial measure under IFRS Accounting Standards and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. For further information, refer to the "Operating Netbacks" section of our management's discussion and analysis for the year ended December 31, 2025, which is incorporated herein by reference, and available on SEDAR+ at sedarplus.ca.
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44 RESEARCH COVERAGE • ATB Capital Markets • BMO Capital Markets • Canaccord Genuity • Capital One Securities • CIBC World Markets • Desjardins Capital Markets • Haywood Securities • Jefferies • National Bank Financial • Peters & Co. • Raymond James • RBC Capital Markets • Scotiabank Global • TD Securities • TPH & Co.