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CORPORATE PRESENTATION TSX : SOIL OTCQX : OILSF SATURN OIL + GAS INC . A Proven Blueprint for Unlocking Value August 2026
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 2 Disclaimer This presentation is for informational purposes only and is not intended as a solicitation or offering of securities of Saturn Oil & Gas Inc. (“Saturn” or the “Company") in any jurisdiction. The material presented is not intended to modify, qualify, supplement or amend information disclosed under corporate and securities legislation of any jurisdiction applicable to Saturn and should not be used for the purpose of making investment decisions concerning Saturn securities. All dollar figures included herein are presented in Canadian dollars, unless otherwise noted. Forward-Looking Statements This presentation contains "forward-looking statements" including estimates of future production, cash flows and reserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrases such as "expects" or "does not expect", "is expected", "anticipates" or "does not anticipate", "plans", or "estimated", or stating that certain actions, events or results “may", "could", "would", "might" or "will" be taken, occur or be achieved). In particular, this presentation contains forward- looking statements pertaining to the following: Saturn’s anticipated capital budgets and average daily production, production and free funds flow growth, target net debt, continued margin expansion, target production rate, forecast netback components, the ability of the Company to maintain its balance sheet strength; type well economics and performance; drilling inventory and reserve life index expectations; expectations regarding break-up conditions and funds flow in Q2, expectations concerning the Q2 and balance of 2026 capital program, planned OHML drilling and advantages thereof; our ability to enhance size, scale and production per share metrics; Saturn’s strategy to increase recovery factors; the ability of the Company to manage fluctuating commodity prices; the Company’s business strategy (including development, enhancement, acquisition and risk management); capital cost, cost per well, NPV, rate of return and payout. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. There are numerous uncertainties inherent in estimating crude oil, natural gas and NGL reserves and the future cash flow attributed to such reserves. All forward-looking statements are based on Saturn's beliefs and assumptions based on information available at the time the assumption was made. Saturn believes that the expectations reflected in these forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward- looking statements included in this presentation should not be unduly relied upon. Saturn’s plans could change in response to commodity price fluctuations. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. In addition, risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil; delays in business operations; processing restrictions; blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry. These risks and others are described in more detail in the Company’s Annual Information Form for the year ended December 31, 2025, filed on SEDAR+ at www.SEDARPLUS.ca These risks and uncertainties could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent. Saturn assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Certain information contained herein have been prepared by third- party sources. The information provided herein has not been independently audited or verified by the Company. S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 2
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 3 01. Diversified Asset Base • >80% weighted to high-value light oil & liquids • Consistent type curve outperformance (23% in 2025 / 22% in 2024)(3) • Record 2025 production, adjusted funds flow & free funds flow(1) The Saturn Investment Opportunity (TSX: SOIL) High-Quality Light Oil Weighted Assets, Free Funds Flow Generation and Per Share NAV Disconnect Downside Protection • Discounted valuation + 50% free funds flow yield(1,2) at year-end ‘25 • Risk management protects the downside • Flexible capital program allows rapid shifting in response to commodity prices 02. Compelling Upside • Potential for rerate with consistent performance & deleveraging • Per share metrics significantly improved with NCIB & SIB • Disconnect between market value and $7.75/sh (1P) net asset value(1) creates opportunity 03. 1) See disclaimer “Information Regarding Non-GAAP and Other Financial Measures” 2) Based on Saturn’s year end 2025 market cap and 2025 annual free funds flow 3) See disclaimer “Oil and Gas Advisories”
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4 S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 01. 0.2 1.9 7.0 7.3 7.5 7.3 11.0 12.5 17.8 26.0 26.3 26.9 26.4 30.1 39.0 41.1 41.7 40.4 41.1 43.7 43.1 41.4 48 - 50 Q1 2021 Q2 Q3 Q4 Q1 2022 Q2 Q3 Q4 Q1 2023 Q2 Q3 Q4 Q1 2024 Q2 Q3 Q4 Q1 2025 Q2 Q3 Q4 Q1 2026 Q2 Est. Exit 2026 Adde 5-YEAR PRODUCTION HISTORY (MBoe/d) (3) Corporate Profile Saturn is a Low Decline, Low Royalty, Light Oil Producer Leveraging Our Saskatchewan Advantage 1) Net debt as at June 30, 2026 and shares outstanding as at Jul 29/26. 2) See disclaimer “Information Regarding Non-GAAP and Other Financial Measures” 3) Historical production breakdown by product available within the Company’s MD&A’s for the corresponding periods filed on SEDAR 4) Q2/26 over Q2/25. Calculated by converting quarter end net debt to shares, adding that to the basic shares outstanding at quarter end and dividing the total production in boe during the quarter by the debt adjusted shares. 5) Based on available data from IRWIN and other available ownership sources. Capital Structure ($C) (TSX: SOIL | OTCQX: OILSF) Shares Outstanding(1) (Basic) 178.0 MM Basic Market Capitalization (Aug 4/26) ~$955.1 MM Net Debt(1,2) $761.6 MM Enterprise Value (EV) ~$1.7 B Significant Shareholders(5) GMT Capital Corp 30% Libra Advisors LLC / Tandon Family Foundation 13% Mackenzie Financial Corp. 6% Equinox Partners 6% 1832 (Scotia Global Asset Management 3% The Huginn Fund 2% Black Maple 2% Bison Interests 2% Penderfund Capital Management 2% Nokomis Capital 2% Charlestown Capital Advisors 1% American Century Investment Mgmt 1% Other Institutions ~2% Visible Institutional Holders ~72% Insiders ~2% +86% Compound Annual Growth Rate Q2 2021 to Q2 2026 +66% Growth per debt- adjusted share(4)
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 5 Acquire mid-life cycle assets at attractive valuations & integrate seamlessly Our Blueprint for Value Creation Simple Blueprint Saturn Follows to Enhance Size, Scale and Production Per Share Metrics Optimize to reduce costs by streamlining operations, optimizing volumes & improving margins Develop to expand reserves and locations, enhance asset performance & drive free funds flow(1) generation 1) See disclaimer “Information Regarding Non-GAAP and Other Financial Measures” 01 02 03 04 Acquire Optimize Develop Reduce Net Debt to Repeat 55S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F Reduce Net Debt target ≤1.0x net debt to adjusted EBITDA(1) 12-18 months post- closing and look to repeat
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 6 01. Saturn’s Blueprint in Action: Growth Trajectory Asset Base Growth & Production Expansion Increases Ability to Generate Free Funds Flow(1) 2022 2023 2024 2021 2025 Battrum/Flat Lake Ridgeback Viking Oxbow Acquisition 2020 ~48-50,000 B O E / D 2 0 2 6 EX I T T A R G E T Five significant acquisitions, totaling ~$1.6 billion, drove growth from ~300 boe/d to a targeted 2026 exit of ~48-50,000 boe/d Acquisitions resulted in a diversified asset base with strong free funds flow(1) generation 1) See disclaimer “Information Regarding Non-GAAP and Other Financial Measures” June 2021 Oxbow (SE Saskatchewan) $82MM Acquired 6,400 boe/d Paid ~1.2x Forward CF July 2022 Viking (West Saskatchewan) $241MM Acquired 4,000 boe/d Paid ~1.9x Forward CF 2026 Burgess/Triland February 2023 Ridgeback (SE Sask & Alberta) $526MM Acquired 17,000 boe/d Paid ~1.7x Forward CF June 2024 Battrum/Flat Lake (South Saskatchewan) $535MM Acquired 13,000 boe/d Paid ~2.1x Forward CF July 2026 Burgess/Triland (SE Saskatchewan) $173MM Acquired ~3,700 boe/d Paid <2x Forward CF ~300 B O E / D
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 7 01. Oil-Weighted Assets Across Three Core Areas Portfolio of Low-Decline, High-Return Plays Targets Multiple Stacked Oil Zones Central AB SE SK West Central SK Montney Cardium Lochend West Pembina Brazeau Kaybob 2023 2023 & 2025 Lower Shaunavon / Mannville Viking Viking Kindersley Plato Herschel Battrum 2020 2022 2024 1) See disclaimer “Identified Inventory” ~2,600 Identified Drilling Locations(1) ~20 Yrs Development Inventory Bakken / Midale Oungre / Torquay Mississippian Manor (Spearfish) Carnduff Viewfield Flat Lake 2023 2021 & 2025 2024 2026 Existing Newly Acquired 2026
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8 S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 01. Burgess Creek & Triland Core-Up Acquisitions (1) Based on Q1/26 lease operating statements. (2) Based on Company prepared internal projections. (3) Forecast 2026 estimated net operating income (at US$80 WTI) (4) See disclaimer “Identified Inventory” Continuation of Blueprint Strategy Expands Size & Scale in Core SE Saskatchewan Area BURGESS CREEK & TRILAND ASSETS FIT PERFECTLY WITHIN SATURN’S SE SK AREASTRATEGIC HIGHLIGHTS 2026 2026 2026 2026 Light oil-weighted production in core SE Saskatchewan area increases scale & margins • ~3,700 boe/d acquired (~97% light oil & liquids)(1) • Accretive netbacks Acquired at low cash flow multiple & sub-PDP value on purchase price • ~1.8x CF multiple(1) • ~80% of reserve PDP(NPV10)(2) Assets bring deep location inventory with high- tier drilling targets • >400 gross identified locations(2,4) • Includes >40 un-booked OHML locations(2,4) Synergies further enhance Saturn’s ‘Core-Up’ strategy • $7MM identified synergies (NPV10 on PDP)(3) • Expected opex reduction ~$2.50/bbl(3)
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 9 02. 15.4% 12.8% 11.5% 12.6% 11.9% 12.8% 0% 3% 6% 9% 12% 15% 2021 2022 2023 2024 2025 Q2 2026 OPERATING & TRANSPORTATION COSTS (1) ($/BOE) Optimization: Controlling What We Can 1) See disclaimer “Information Regarding Disclosure on Oil and Gas Operational Information and Non-IFRS Measures.” 2) Field operating netback, before the impact of derivatives. $36.38 $66.20 $47.64 $43.07 $36.18 $60.14 $0 $20 $40 $60 $80 $100 $120 $0 $10 $20 $30 $40 $50 $60 $70 2021 2022 2023 2024 2025 Q2 2026 WTI Price (USD) Field Operating Netback (C$/boe)1,2 Operating Netback (CAD) Average WTI (USD) ROYALTIES Royalties 2021 – Q2/26 17% 27.96 25.28 21.61 19.01 19.09 20.98 0.74 0.61 1.28 1.39 1.57 1.75 $0 $5 $10 $15 $20 $25 $30 $35 2021 2022 2023 2024 2025 Q2 2026 Operating Expenses Transportation Expenses Opex 2021 – Q2/26 25% Applying Saturn’s Blueprint Contributes to Ongoing Margin Expansion Q2/26 Field Operating Netback vs 2021(2) 65% FIELD OPERATING NETBACK (1,2)
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 10 02. Operating Cost Reductions & Streamlining Size and Scale Supports Ability to Capture Efficiencies KEY OPEX(1) REDUCTION DRIVERS Fees • Increased due to gas processing fees on acquired properties Repairs & Maintenance / Workovers • Restored shut-in wells post-acquisition to increase production, and completed deferred maintenance to optimize facilities(2) Utilities • Secured lower utility rates through hedge contracts, supported by SK Carbon tax elimination • Production volumes added in AB due to drilling benefits from competitive utility rates • Reduced utility / energy usage following sale of Deer Mountain Rentals • Higher production reduces per unit fixed costs (lower $/boe) • Lower rental costs per unit in AB due to incremental production volumes added following drilling Field & Labour • Reflects synergy capture in key operating regions, as we are able to streamline headcount and reduce overhead as we core-up • Per unit fixed costs decline as production increases (lower $/boe) 1 2 3 4 5 1 2 3 4 5 27.53 1.20 (2.83) (2.64) (1.68) (1.41) (1.06) 19.09 Net Operating Costs ($/Boe) $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 OPERATING COST(1) REDUCTION COMPONENTS (2021 to 2025 - $/BOE) 1) See disclaimer “Information Regarding Non-GAAP and Other Financial Measures” 2) R&M does not fluctuate proportionally with production increases
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 11 03. 644 510 387 383 381 358 333 35 0 200 400 600 800 1000 Mississippian/Spearfish Bakken/Torquay (Frac) Deep Basin (Cardium/Montney) Bakken/Spe arfish (OHML) Viking Shaunavon/Success Gross Locations 2025 IDENTIFIED LOCATION COUNT + AVERAGE WELL PERFORMANCE VS TYPE CURVE (1, 2) Saturn SE SK Development Advancement (1) See disclaimer “Initial Production Rates”. (2) See disclaimer “Identified Inventory”. (3) See disclaimer “Type Curve” . (4) Based on Company prepared internal projections. TYPE CURVE OUTPERFORMANCE DRIVES STRONG RETURNS > 10.0 > 10.0 > 10.0 > 10.0 > 10.0 > 10.0 > 10.0 > 10.0 > 10.0 > 10.0 > 10.0 0 2 4 6 8 10 Eagle Ford - Non-Core STACK - Core ND Bakken/Three Forks - Non-Core SCOOP - Core Eagle Ford - Core Viking Dodsland Cardium Oil Permian Midland - Non-Core Duvernay ESB Uinta - Core PRB Turner - Core DJ Basin - Core Permian Delaware - Non-Core Utica Oil Window Conventional Heavy Oil Single-Leg Hz Southern AB Mannville Oil Duvernay WSB Permian Midland - Core ND Bakken/Three Forks - Core Clearwater South Fairway Montney Oil Alberta Permian Delaware - Core Charlie Lake Saturn's OHML Bakken - SE SK SK Mississippian Conventional Conventional Heavy Oil Multilateral Frobisher Dual Leg Years PRIMARY PAYOUT PERIODS* (YEARS) Half-Cycle Payout Period 2x Half-Cycle Payout Period * Peters & Co. Research (Oct/25). Due to limited production duration, Bakken OHML wells are not yet included in the Peters’ data set. The estimated payouts shown here are internal estimates by Saturn. Mississippian/ Spearfish Bakken / Torquay (Frac) Deep Basin (Cardium/ Montney) Bakken/ Spearfish (OHML) Viking Shauanvon / Success 48% (31 wells) 13% (19 wells) 5% (5 wells) 8% (7 wells) 17% (12 wells) Relative to Type Curve 25% (18 wells) $10,898 Capital Efficiency $/boe/d $15,950 $12,652 $12,671 $17,894 $21,205 Avg IP30 110 boe/d 121 boe/d 381 boe/d 233 boe/d 84 boe/d 93 boe/d Saturn’s average 2025 well performance vs type curve +23% Production - IP30 Performance – Top Tier Inventory Saturn Identified Locations BCX Identified Locations(4)
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 12 03. 2026 Development: SE SK OHML Program Saturn is the Leading Developer of Open Hole Multi-Lateral (OHML) Technology in Saskatchewan • Saturn is a leading developer of OHML wells in SK; the only company to deploy this drilling technique across four formations in SE SK • 70% increase in Saturn’s OHML wells targeted in 2026 vs 2025 • 20% improvement on our drill rates in the Bakken from 2023 to 2025 • Open hole provides distinct advantages vs cased hole ✓ Greater reservoir exposure = more area contacted ✓ Entire well bore open to inflow vs just frac ports = enhanced production rates ✓ Targeted laterals avoid contact with wet zones = reduced risk ✓ Lower water production = lower opex 37 OHML planned locations in 2026 >380 OHML locations identified in SE SK(1) 20% of 2026 development capital allocated to OHML Cased Hole Open Hole up to 1) See disclaimer “Identified Inventory”
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 13 03. 2026 Development: SE SK Conventional Program Conventional Development Program Provides Flexibility with Strong Returns • Conventional Mississippian & Spearfish wells have Saturn’s lowest drilling costs with high deliverability, resulting in the most capital efficient wells • Conventional wells enhance our drilling portfolio: ✓ Represent 9 of our top 10 most capital efficient wells drilled in 2025 ✓ Robust economics even in soft commodity environment ✓ Short cycle times enhance flexibility ✓ Variety of zones and pools in which to find opportunities ✓ Competitive advantage from leveraging our infrastructure network ✓ Re-entry opportunities reduce capital and utilize existing wellbores 36 Conventional wells planned >640 Conventional locations identified in SE SK(1) #1 returns Highest ranked plays in Saturn’s inventory #1 Most capital efficient well Saturn drilled in ’25 #2 Most capital efficient well Saturn drilled in ’25 0 50 100 150 200 250 300 350 400 450 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 BOE/D Type Curve IP30 Actual IP30 - 27 Drills 101/03-32-002-34W1/0 101/16-32-002-34W1/0 >50% Above 2025 Guidance Type Curve 1) See disclaimer “Type Curve”1) See disclaimer “Identified Inventory”
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S AT U R N O I L + G AS | P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 14 03. Initial Creelman Development • 18.5 sections of 100% WI land adjacent to existing waterflood • 70 MMbbls OOIP, 5% increased waterflood recovery, plus up to 40 re-pressurized infill drills • Converted 7 producers to injectors and 1 producer to source well in 2025 • 7 further conversions, providing pressure support for 3 infill drills in 2026, plus planned infill drills in 2027 Future Expansion • Potential to implement identified in surrounding areas • >100 sections of waterflood development opportunity Creelman Secondary Expansion Future Expansion Future Expansion 40 Future Creelman re-pressurized drill locations >300 Potential Bakken injector conversion in expansion areas 2026 Development: Creelman Waterflood Expansion Progressing Secondary Recovery, Re-Pressurizing Infill Drilling and Supporting Sustainability
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 15 03. 2026 Development: AB Cardium Innovative Longer Laterals and Multi-Pad Development Boost Economics & Capital Efficiencies Saturn’s Cardium Approach • Enhancing the Cardium inventory value by adopting new technologies that enable extended reach horizontal (“ERHz”) wells • Saturn drilled the fastest ERHz Cardium well on record in Q3/25, drilling to 5,090 metres MD in a single run & achieved well completion from surface casing to total depth in only 4.8 days • Saturn drilled the longest Cardium well on record at 7.57 kms or 24,800 ft. • 2-mile well has 1.3x capital costs with 2x reservoir exposure • 3-mile well has 1.6x capital costs with 3x reservoir exposure • Cardium delivers Saturn’s highest production wells • Increased pad size due to land concentration strategy 2025 SATURN ALBERTA DEVELOPMENT WELLS ON TOP 10 LIST (2) UWI Formation Category Month Rank 100/05-02-026-03W5/00 Cardium Top Cardium Monthly Vols Apr/25 4 100/01-29-025-02W5/00 Cardium Top Cardium Monthly Vols May/25 4 EXTENDED REACH MULTI WELL PAD DEVELOPMENT AT WEST PEMBINA 1) See disclaimer “Type Curve” 2) Source: ATB Cormark Capital Markets
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 16 04. Q2/26 Highlights: Exceeding Expectations Positive Momentum Continues in Q2 2026 Performance 1) See disclaimer “Information Regarding Non-GAAP and Other Financial Measures” 2) See disclaimer “Supplemental Information Regarding Product Types” 3) Based on Saturn’s Q2 2026 market cap and 2026 annual free funds flow 4) Q2/26 over Q2/25. Calculated by converting quarter end net debt to shares, adding that to the basic shares outstanding at quarter end and dividing the total production in boe during the quarter by the debt adjusted shares.. 41,447 boe/d(2) Average volumes exceed guidance for 8th consecutive quarter Reflects strong production volumes and supportive pricing $359 M PRODUCTION EXCEEDS GUIDANCE SYSTEMATIC DEBT REPAYMENT CONTINUES RECORD QUARTERLY REVENUE 1.3 X Net debt / Adj. EBITDA(1) at Q2/26Growth in production per debt- adjusted share(1,3) vs Q2/25 +66% EXPANDING PRODUCTION PER SHAREFREE FUNDS FLOW BEAT EXPECTATIONS (1) $82.5MM Directed to debt repayment, tuck-in acquisitions & returning capital $ 0 . 46 / sh Ongoing strategy execution benefitted from higher oil prices $123 M ROBUST ADJUSTED FUNDS FLOW (1) $ 0 . 68 / sh
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 17 04. Capital Return Framework • Normal Course Issuer Bid completed early in Jul/26 (12.1MM maximum shares; ~65,400 shares daily) • Substantial Issuer Bid closed Jul 16/25 (~1.6 MM shares repurchased at $2.15 per share) Fueling Free Cash Flow and Disciplined Capital Allocation Focus on Generating Strong Free Funds Flow and Increasing Value Per Share Shares repurchased via NCIB + SIB (Aug/24-Jul/26) ~12% of shares outstanding at launch of NCIB in Aug/24 24.2 MM Returned to Shareholders via NCIB + SIB since Aug/24 ~7% of current market cap(3) ~$66 MM 1) See disclaimer ““Information Regarding Non-GAAP and Other Financial Measures” 2) Normalized AFF (before one-time $20MM cost for early termination payment to unwind certain legacy WTI oil hedges contracted at a low price; opportunistically monetized when oil prices dropped and costs became substantially less expensive) 3) Based on market cap of ~$1.0B; using Aug 5, 2026, shares outstanding $14.5 $40.0 $50.7 $54.5 $67.0 $76.5 $80.2 $68.2 $88.6 $94.1 $129.2 $131.1 $108.9 $103.3 $120.7 $107.2 $122.6 19.9(2) $0 $20 $40 $60 $80 $100 $120 $140 $160 Q2 2022 Q3 Q4 Q1 2023 Q2 Q3 Q4 Q1 2024 Q2 Q3 Q4 Q1 2025 Q2 Q3 Q4 Q1 2026 Q2 WTI in $CAD AFF ($MM) WTI ($CAD) ADJUSTED FUNDS FLOW (“AFF”) (1) GROWTH ($ MILLIONS) AFF(1) in Last 12 Months $454 MM
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 18 04. 2026 Updated Guidance Details Current Price Environment Supports Increased Activity with Continued Focus on Free Funds Flow ~85% Of 2026 budget allocated to DCET ~$20MM AFF(2) impact on 2H/26 for every $5/bbl WTI change Factor Change Approximate AFF(2)(6) Impact WTI Oil Price USD/bbl +/- $5.00 Oil Production Bbl/d +/- 1,000 Exchange Rate CAD/USD +/- $0.01 AECO Gas Price CAD/GJ +/- $0.50 1) 2026 production at midpoint is anticipated to be comprised of ~65% light and medium crude oil, 8% heavy oil, 9% NGLs & 18% natural gas 2) See Disclaimer “Information Regarding Disclosure on Oil & Gas Operational Information and Non-IFRS Measures” 3) Based on 181 million weighted average basic common shares outstanding in 2026 4) In addition, ~$15 MM to be allocated to capitalized administrative costs, ~$19 MM to ARO & $16 MM primarily to lease payments. Not expecting to be taxable in 2026. 5) 2026 updated pricing assumptions: WTI crude oil of US$80.00 WTI, US$3.50 MSW-WTI differential, US$15.50 WCS-WTI differential, C$2.25/GJ AECO and 0.71x CAD/USD +/- $20 MM +/- $18 MM +/- $8 MM +/- $3 MM Revised 2026 Guidance (US $80 WTI)(4),(5) Original Guidance (US $60 WTI) Updated Guidance Development Capital Expenditures ($MM) (2),(5) $180 - $190 $355 - $375 Annual Average Production (boe/d) (1) 39,000 - 41,000 43,000 - 44,000 Oil & Liquids Weighting (%) ~81% ~82% Exit Volumes (boe/d) N/A 50,000 Adjusted Funds Flow (AFF) (2) ($MM) $325 - $375 $535 - $570 AFF Per Share (2),(3) $1.75 - $2.00 $2.95 - $3.15 Free Funds Flow (2)($MM) $120 - $170 $150 - $200 Free Funds Flow Per Share (2),(3) $0.65 - $0.95 $0.80 - $1.10 Year-end Net Debt(2) ($MM) $645 - $695 $955 - $990 Net Debt to Proforma Adj. EBITDA(2) (times) 1.4x - 1.7x 1.3x - 1.5x Operating Netback(2) Inputs Original Guidance (US $60 WTI) Updated Guidance Royalties (%) 12.0% - 12.5% 12.0% - 12.5% Net Operating Expense ($/boe) (2) $20.00 - $21.00 $20.00 - $21.00 Transportation Expense ($/boe) $1.70 - $1.85 $1.70 - $1.85 General & Administrative Expense ($/boe) $1.70 - $1.85 $1.70 - $1.85 SECOND HALF 2026 SENSITIVITIES
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 19 04. Refinancing Senior Notes Enhances Liquidity Increased Financial Flexibility Supports Multiple Paths to Value Creation 1) Net of royalties STRATEGIC BENEFITS Reduced Costs • Lowered blended interest expense by ~2% • Improved cash flow retention Expanded Flexibility • Unsecured structure • Relaxed covenant framework • Replaced mandatory 10% amortization payment with semi-annual offer to repurchase 2.5% of principal at 101% Increased Tenor • Maturity extended 2 years to 2031 New Issue: Senior Unsecured Notes Maturing 2031 US$575MM @ 8.5% CAD$185MM @ 7.5% + Amended Credit Facility Provides Added Liquidity $200MM Elected commitment $500MM Borrowing base + commitments 40-60% Oil & liquids(1) hedge target Active Hedge Strategy Protects Downside Hedge differentials, natural gas & foreign exchange+
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 20 2.8x 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 1 SOIL 2 3 4 5 6 7 8 9 10 11 12 Peer Group Peer Comparison & Research Coverage 2027E FREE CASH FLOW YIELD (1,3) 2027E ENTERPRISE VALUE / DEBT ADJUSTED CASH FLOW (EV/DACF) (2,3) Avg: 4.6x Saturn Positioned for Strong Free Cash Flow to Support Debt Repayment and Return of Capital 1) Comparative Canadian company FCF Yields are sourced from ROTH Canada research dated July 13, 2026, and are based on ROTH’s Canadian energy coverage comparables. Peers shown in the chart include IPO, SGY, GTE, SCR, KEL, TOU, SDE, LGN, POU. 2) Comparative Canadian company valuations of EV/DACF (unhedged) are sourced from Peters & Co. research dated July 27, 2026. EV equals the sum of equity market capitalization plus Net Debt; DACF is Debt Adjusted Cash Flow meaning 2026E cash flow on forward strip adjusted for financing expenses and unhedged. Peers shown in the chart include BNE, SGY, OBE, BTE, JOY, LGN, WCP, SCR, TVE, HWX, ATH & IPCO. 3) See disclaimer “Information Regarding Non-GAAP and Other Financial Measures” 28.0% -12% -8% -4% 0% 4% 8% 12% 16% 20% 24% 28% 32% SOIL 1 2 3 4 5 6 7 8 9 Peer Group Avg: 10.6% Firm Analyst Rating Most Recent Report Target Price ATB Cormark Capital Markets Amir Arif, CFA | aarif@atb.com Outperform $8.50 Canaccord Genuity Inc. Mike Mueller | mmueller@cgf.com Buy $7.50 National Bank of Canada Financial Markets Dan Payne, CFA | dan.payne@nbc.ca Sector Perform $8.00 Peters & Co. Limited Christian Comeau | ccomeau@petersco.com Sector Perform $8.00 Roth Canada Jamie Somerville | jsomerville@rothcanada.ca Buy $10.00 Velocity Trade Capital, Canada Mark Heim, CFA | mark.heim@velocitytradecapital.com Outperform $7.50 Ventum Capital Markets Adam Gill | adam.gill@ventumfinancial.com Buy $9.00
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 21 01. Diversified Asset Base • >80% weighted to high-value light oil & liquids • Consistent type curve outperformance (23% in 2025 / 22% in 2024)(3) • Record 2025 production, adjusted funds flow & free funds flow(1) The Saturn Investment Opportunity (TSX: SOIL) High-Quality Light Oil Weighted Assets, Free Funds Flow Generation and Per Share NAV Disconnect Downside Protection • Discounted valuation + 50% free funds flow yield(1,2) at year-end ‘25 • Risk management protects the downside • Flexible capital program allows rapid shifting in response to commodity prices 02. Compelling Upside • Potential for rerate with consistent performance & deleveraging • Per share metrics significantly improved with NCIB & SIB • Disconnect between market value and $7.75/sh (1P) net asset value(1) creates opportunity 03. 1) See disclaimer “Information Regarding Non-GAAP and Other Financial Measures” 2) Based on Saturn’s year end 2025 market cap and 2025 annual free funds flow 3) See disclaimer “Oil and Gas Advisories”
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 22 Head Office Saturn Oil & Gas Inc. Suite 2500, 600 – 3rd Ave SW Calgary, AB T2P 0G5 info@saturnoil.com 403.268.7800 TSX: SOIL | OTC QX: OILSF
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 23 Appendix
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24 S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 01. Saturn’s Community Involvement $250,000 2026 budget for sponsorships and charitable contributions Driving Positive Change Through Diversified Partnerships, Donations, and Volunteering Fostering Healthy and Vibrant Communities Saturn is committed to driving positive change through strategic partnerships and targeted donations. Our approach emphasizes building meaningful relationships, supporting local economies, and enhancing community well-being. By diversifying our sponsorships and volunteer initiatives, we aim to deliver lasting benefits across multiple focus areas in the communities where we operate. Key Priorities • Children’s Health: Hospitals and health foundations centered around supporting children and their families as they navigate illness • Cancer: Organizations targeting research, treatment and preventative measures for cancer and cancer-related issues • Mental Health: Supporting organizations that raise awareness, reduce stigmas, and fund initiatives to improve mental health and wellbeing • Food Security: Contributing to local food banks to help address hunger Some of Our Previous and Ongoing Support has Included: Rural & Local FOOD BANKS
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 25 Saturn’s OHML Development Program Open Hole Multi-Lateral (OHML) Development is Cornerstone of Saturn’s SE Saskatchewan Program Drilling • Bakken/Torquay historically fracked; uneconomic in thinner reservoirs as stimulation not maintained within formation – water from offsetting formations can migrate • 1st and only operator in Canada to drill an OHML Spearfish well (3 drilled to date) – 3rd OHML Spearfish well (16-05) came on at 330 boe/d(1), ~3x type curve expectations(2) • Two Midale OHML re-entries in Q4/25 have up to 6 legs each, and Saturn drilled the first of two Torquay OHML wells in 2026; early results exceeding expectations Results • OHML inventory(3) represents 15% of our ~2,600 total identified locations, and has essentially doubled every year for the last three years as we progress to other plays • OHML comprises some of the more prolific wells recently drilled in SK (11-21-11-6W2, 15-21-11-6W2, and 16-21-11-6W2) • Industry-wide Bakken OHML production has grown from 0 to >2,500 boe/d in less than three years; ~35 wells have been drilled 2025 SATURN SK OHML DEVELOPMENT WELLS ON TOP 10 LIST (4) UWI Formation Category Month Rank 101/16-21-011-06W2/00 Bakken Top 'Oil' Monthly Vols Sept/25 7 101/16-21-011-06W2/00 Bakken Top 'Oil' IP Rates Sept/25 7 101/15-21-011-06W2/00 Bakken Top 'Oil' Monthly Vols May/25 3 101/15-21-011-06W2/00 Bakken Top 'Oil' IP Rates May/25 4 101/11-21-011-06W2/00 Bakken Top 'Oil' IP Rates Jul/24 2 0 100 200 300 400 500 YE 2022 YE 2023 YE 2024 YE 2025 Location Count Midale Torquay Spearfish Bakken 200% 2023-2024 OHML INVENTORY (3) GROWTH OVER TIME SATURN’S SE SK OHML DRILLS & LOCATION INVENTORY (3) 186% 2024-2025 1) See disclaimer “Initial Production Rates” 2) See disclaimer “Type Curve” 3) See disclaimer “Identified Inventory” 4) Source: ATB Cormark Capital Markets
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 26 Alberta Operations – Montney & Cardium Longer Laterals and Innovative Completions Boosting Economics & Capital Efficiencies Cardium • Saturn drilled the fastest extended reach Hz Cardium well on record in Q3/25, drilling to 5,090 metres MD in a single run - achieved well completion from surface casing to total depth in only 4.8 days Kaybob Montney • Finalized drilling and completion of Kaybob Montney 3-well pad, featuring 3-mile extended reach laterals - the longest laterals on record to be drilled in Kaybob • North well on the pad has the most productive days and is already exceeding type curve expectations • South 2 wells still cleaning up, but based on reservoir quality observed while drilling, a consistent result to the north well is expected once peak production reached 2025 SATURN ALBERTA DEVELOPMENT WELLS ON TOP 10 LIST (2) UWI Formation Category Month Rank 100/05-02-026-03W5/00 Cardium Top Cardium Monthly Vols Apr/25 4 100/01-29-025-02W5/00 Cardium Top Cardium Monthly Vols May/25 4 - 250 500 750 1,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 BOE/D Days Lochend Type Curve 101/05-02-026-03W5 101/01-29-025-02W5 101/06-29-025-02W5 101/04-02-026-03W5 EVOLUTION OF THE CARDIUM SINCE 2004 TYPE CURVE (1) OUTPERFORMANCE – 4 LOCHEND WELLS IP30 1) See disclaimer “Type Curve” 2) Source: ATB Cormark Capital Markets
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 27 C ENTRAL ALB ERTA 11,577 boe/d(1) 6,049 boe/d(1) 23,821 boe/d(1) WEST SASKATC HEWAN SOUTHEAST SASKATC HEWAN 1) See disclaimer “Supplemental Information Regarding Product Types” 2) See disclaimer “Identified Inventory” Three diversified, light oil, core operating areas across 1.5 MM acres of land, generating 41,447 boe/d(1) in Q2 2026 Saturn’s Operations Portfolio of Low-Decline, High-Return Plays Targets Multiple Stacked Oil Zones • Focus on mid-life cycle assets with high oil weighting • Similar full and half cycle costs since infrastructure already built out • Assets feature low decline, lower cost, repeatable wells which mitigates risk • Optimize assets, deploy technology, leverage knowledge and learnings across our portfolio to unlock value S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N ~2.6 K Identified Drilling Locations(2) ~20 Yrs Development Inventory ~22 % Decline Rate
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 28 Southeast Saskatchewan Anchor Area with High Rate of Return, Abundant Seismic Coverage, Large Scale Owned Infrastructure Area Map • Flat Lake • Viewfield • Oxbow Overview Play Development: • Viewfield: Bakken (OHML & Frac) • Oxbow: Frobisher, Midale, Spearfish, Torquay (OHML & conventional) • Flat Lake: Torquay / Bakken (Frac), Oungre (conventional) 2026 Capital Development Focus: 100 (87.2 net) wells planned in SE Sask; ~20% of 2026 capital directed to OHML drills • 37 (28.2 net) Bakken/Spearfish/Midale/Torquay OHML well locations targeted • OHML Play Expansion – Drilled Saturn’s first Midale and Torquay OHML wells; plan to drill first P2 Spearfish & Lower Shaunavon OHML wells in 2026 Conventional Mississippian and Spearfish delineation • ~36 gross wells planned in 2026 – highly capital efficient Expanding Bakken waterflood at Creelman • ~5% of total 2026 capital earmarked for waterflood • 14 conversions to injectors in 2026, providing pressure support for 3 infill drills in 2026 + planned infill drills in 2027 Q2/26 Production Of Total Volumes 57% 23,821 Boe/d Oxbow Viewfield Flat Lake Torquay Development Program Bakken PP Drills OHML Bakken Wells Bakken Waterflood Program OHML Spearfish Wells Mississippian Focused Wells 15-21 OHML Well Existing Newly Acquired
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 29 West Saskatchewan Resource Plays, Repeatability, Steady Production and Cash Flow • Kindersley • Herschel • Plato • Battrum Overview Q2/26 Production Of Total Volumes 15% 6,049 Boe/d Play Development: • Kindersley, Herschel and Plato: Viking • Battrum: Success / Lower Shaunavon • Waterflood in Cantuar / Battrum Units 2026 Capital Development Focus: ~18% of 2026 capital allocated to this area ($57MM) • Capital acceleration from H2/26 into Q2/26 enabled a rig to be added in this area • Anticipate drilling 37 (32.0 net) wells in this area in 2026 • Viking & Success plays offer inventory of short cycle- time locations - drilling can restart rapidly and volumes can be brought on within weeks Area Map Success Development Viking Resource Development & Delineation Viking Resource Development Kindersley Herschel Plato Battrum
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 30 • Kaybob • West + East Pembina • Brazeau • Lochend Central Alberta Resource Play, Large Prospect Inventory, Significant Expansion Potential Area MapOverview Q2/26 Production Of Total Volumes 28% 11,577 Boe/d Saturn 4-2 well; Longest Cardium lateral ever drilled in Canada (7,570m) Brazeau Acquisition and Record Corporate Wells Kaybob E. Pembina W. Pembina Brazeau Lochend 7-30 Pad Montney Wells Play Development: • E/W Pembina, Brazeau: Cardium • Kaybob: Montney 2026 Capital Development Focus: Enhancing the Cardium inventory value • ~24% of 2026 capital allocated to continued Cardium development at Lochend and West Pembina • Drilling seven-well pad featuring extended reach horizontals up to 3-miles – longest ever drilled in the West Pembina area • Production optimization in Kaybob continues to occur with gas lift to pump jack conversions • Potential to drill Brazeau Cardium wells Existing Newly Acquired
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 31 John Jeffrey Chief Executive Officer Former CFO and founding partner of Axiom Group, which drilled >1,000 wells for oil & gas clients in Western Canada Has led Saturn to successfully grow from ~400 boe/d to ~43,000 boe/d in just over four years Currently serves on the board of EPAC MBA (Finance) from University of Saskatchewan, and B. Comm (Economics) Management A Long History of Value Creation in the Oil & Gas Production Space Justin Kaufmann Chief Development Officer Former Manager of Axiom Group, which drilled >1,000 wells for oil & gas clients in Western Canada Previously held senior management and geology roles for various private and public companies, and consulted for Lightstream Resources and Novus Energy P. Geo (APEGS), and B.Sc. (Geology) from University of Saskatchewan Scott Sanborn Chief Financial Officer Former Corporate Controller of Jupiter Resources Ltd. - sold for $626 million in 2020 Previously held various leadership roles with energy companies including Marquee Energy and Verano Energy, and earlier, worked with KPMG LLP CPA designation, and B. Comm (Accounting) from the University of Calgary Grant MacKenzie Chief Legal Officer Former Partner at Dentons Canada LLP Over 20 years experience in law dealing with public issuers with respect to capital markets, M&A, public offerings and stock exchange compliance Bachelor of Laws (LL.B.) from the University of New Brunswick
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 32 Jamie Kuntz Senior VP Operations Former Facility & Pipeline Engineering Manager at Ridgeback Resources Over 20 years experience in production, facilities and pipelines, and asset management Southern Alberta Institute of Technology with a vocation in Energy & Natural Resources and Chemical Process Operations A Long History of Value Creation in the Oil & Gas Production Space Tyler Cheetham VP Land Former Senior Landman roles at Crescent Point Energy and Husky Energy Over 20 years experience with A&D, land strategy, and leading successful land opportunities and advancements B. Comm from University of Lethbridge and a member of the Canadian Association of Land and Energy Professionals (CALEP) Joel Robertson VP Finance Over 10 years of oil and gas focused accounting experience Previously held roles of increasing responsibility at PFB Corporation and Jupiter Resources Ltd., and prior thereto, serviced clients at KPMG LLP CPA designation, Bachelor of Business Administration (Finance) from Trinity Western University Cindy Gray VP Investor Relations Former CEO and Founder of 5 Quarters Investor Relations Over 20 years experience in financial communications, including senior and executive roles at several public companies, and leading global business development for one of the TSX & TSX-V practice groups MBA from University of Calgary, and BA (Sociology/ Psychology) Management
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 33 03. Jim Payne ▪ CEO of dynaCERT Inc., and CEO of a privately-held consulting, project management and real estate development company operating in the Greater Toronto Area ▪ Over 38 years of experience in strategic leadership roles within both public and private companies, corporate governance, finance and accounting, capital markets, executive leadership and business performance improvements ▪ Graduated St. Clair College in Construction Engineering, Project Management and Estimating John Jeffrey, MBA, BA ▪ Former CFO and founding partner of Axiom Group ▪ Led Saturn to successfully grow from ~400 boe/d to >43,000 boe/d in just over four years ▪ MBA majoring in Finance from University of Saskatchewan, and B. Comm (Economics) Lynn A. Peterson ▪ Former Executive Chair of Chord Energy Corp. (NYSE: CHRD) and previously, served as CEO of Whiting Petroleum Corporation; CEO/Chair of SRC Energy; and was co-founder/Chair/CEO of Kodiak Oil & Gas ▪ 40 years of energy industry experience and extensive senior leadership, governance and operational expertise, particularly in the Williston Basin ▪ Graduated from University of Northern Colorado with a B. Sc. in Accounting Ivan Bergerman, J.D. ▪ Founded Bergerman Smith LLP in 2010 ▪ Extensive experience in public company advisory, IPOs, exempt market distributions, corporate governance, M&A, corporate structuring & restructuring, financing, natural resources, intellectual property and general corporate and commercial ▪ Graduate of University of Saskatchewan, College of Law Andrew Claugus, PE ▪ Entrepreneur and independent businessman with extensive experience in petroleum engineering ▪ Engineering Manager for MECO IV, LLC until the company was sold, after which Mr. Claugus founded Cerrito Energy, a privately backed oil and gas company investing in non-operated interest in core areas of established basins. ▪ Master of Engineering in Petroleum Engineering from the Colorado School of Mines, along with a BSc in Chemical Engineering from Case Western Reserve University Sound Governance and Strategic Oversight Directors Dr. Thomas Gutschlag ▪ Chairman, Cofounder and former CEO/CFO of Deutsche Rohstoff AG, a public company listed on the Frankfurt Stock Exchange with a focus on oil and gas development in the United States ▪ Dr. Gutschlag is a qualified economist with a degree in economics from the University of Heidelberg and a doctorate from the University of Mannheim Chris Ryan ▪ President & CEO for Broadbill Energy Inc.; previously Director of Midstream for Tundra Energy Marketing Ltd. ▪ Authored 25 scientific publications; numerous as Research Scientist at the Canadian Light Source Inc. ▪ Board member of Canadian Crude Quality Technical Association; Co-Chair of the Sampling and Frequency Working Group for the Crude Oil Quality Association; and Honorary founding member of the Global Institute of Water Security S. Janet Yang, MBA, BA ▪ CFO for Reveam, Inc.; previously Research Director, Energy and Mining at GMT Capital Corp. ▪ Former Executive Vice President & CFO of W&T Offshore, Inc. from 2018-2023 ▪ BA Economic from Rice University and MBA from the Booth School of Business at the ▪ University of Chicago
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 34 Information Regarding Non-GAAP and Other Financial Measures Throughout this presentation and in other materials disclosed by the Company, Saturn employs certain measures to analyze financial performance, financial position, and cash flow. These non- GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss), cash flow from operating activities, and cash flow used in investing activities, as indicators of Saturn’s performance. The disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A, including non-GAAP financial measures and ratios, capital management measures and supplementary financial measures in the Company’s Financial Statements and MD&A are incorporated by reference into this presentation. This presentation may use the terms “Adjusted EBITDA”, “Adjusted Funds Flow”, “Net Debt”, “Free Funds Flow”, “Net Debt to Annualized Adjusted EBITDA” and “Net Debt to Annualized AFF” which are capital management financial measures. See the disclosure under “Capital Management” in our Financial Statements and MD&A for the three and six months ended June 30, 2026, for an explanation and composition of these measures and how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures, and, where applicable, a reconciliation of the Company’s historical non-GAAP financial measures to the most directly comparable measure calculated in accordance with IFRS for the applicable period then ended. Disclaimer Oil & Gas Advisories Capital Expenditures The Company uses capital expenditures to monitor its capital investments relative to those budgeted by the Company on an annual basis. Saturn’s capital budget excludes acquisition and disposition activities as well as the accounting impact of any accrual changes or payments under certain lease arrangements. Capital expenditures in this presentation are calculated as expenditures on exploration and evaluation assets, property plant and equipment and excludes the impact of capitalized administrative costs. Adjusted EBITDA The Company considers Adjusted EBITDA to be a key capital management measure as it was used within certain financial covenants prescribed under the Company's previous Senior Term Loan and demonstrates Saturn’s standalone profitability, operating and financial performance in terms of cash flow generation, adjusting for interest related to its capital structure. Adjusted EBITDA is defined by the Company as earnings before interest, taxes, depreciation, amortization and other non-cash or extraordinary items. Adjusted EBITDA is presented both before and after derivatives to identify the impact of WTI commodity contracts hedges in place. Adjusted Funds Flow per Share Adjusted funds flow per share is a non-GAAP ratio by management to better analyze the Company’s performance against prior periods on a more comparable basis. Adjusted funds flow per share is calculated as adjusted funds flow from operations divided by weighted average shares outstanding during the applicable period on a basic or diluted basis. Free Funds Flow, Free Funds Flow per Share and Free Funds Flow Yield The Company uses free funds flow as an indicator of the efficiency and liquidity of its business, measuring its funds after capital investment available to manage debt levels, pursue acquisitions and gauge optionality to pay dividends and/or and return capital to shareholders through activities such as share repurchases. Free funds flow is calculated as adjusted funds flow in the period less capital expenditures. By removing the impact of current period capital expenditures from adjusted funds flow, management monitors its free funds flow to inform its capital allocation decisions. Free funds flow is also presented on a per share basis as a non- GAAP financial ratio. Free funds flow yield is calculated by dividing free funds flow by Saturn’s market capitalization as at year end 2025 ($447.4 million), expressed as a percentage, which is used as a valuation and capital allocation metric. The following table reconciles adjusted funds flow to free funds flow. Royalties as a Percentage of Gross Petroleum and Natural Gas Sales Royalties as a percentage of gross petroleum and natural gas sales is calculated as royalties divided by gross petroleum and natural gas sales. This metric is used by management to quantify the Company’s royalty costs as they relate to revenue before deducting certain processing expenses and to better analyze how royalty rates change over time and compare to prior periods.
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 35 Capital Management Measures National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure (“NI 52-112”) defines a capital management measure as a financial measure that: (i) is intended to enable an individual to evaluate an entity’s objectives, policies and processes for managing the entity’s capital; (ii) is not a component of a line item disclosed in the primary financial statements of the entity; (iii) is disclosed in the notes to the financial statements of the entity; and (iv) is not disclosed in the primary financial statements of the entity. Please refer to note 16 “Capital Management” in Saturn’s financial statements as at and for the period ended June 30, 2026, for additional disclosure on: adjusted working capital deficit (surplus), net debt, adjusted EBITDA, adjusted funds flow, free funds flow, annualized quarterly adjusted funds flow, and net debt to annualized quarterly adjusted funds flow, each of which are capital management measures used by the Company in the MD&A for the quarter ended June 30, 2026. Supplementary Financial Measures NI 52‐112 defines a supplementary financial measure as a financial measure that: (i) is, or is intended to be, disclosed on a periodic basis to depict the historical or expected future financial performance, financial position or cash flow of an entity; (ii) is not disclosed in the financial statements of the entity; (iii) is not a non‐GAAP financial measure; and (iv) is not a non‐GAAP ratio. The supplementary financial measures used in this MD&A are either a per unit disclosure of a corresponding GAAP measure, or a component of a corresponding GAAP measure, presented in the financial statements. Supplementary financial measures that are disclosed on a per unit basis are calculated by dividing the aggregate GAAP measure (or component thereof) by the applicable unit for the period. Supplementary financial measures that are disclosed on a component basis of a corresponding GAAP measure are a granular representation of a financial statement line item and are determined in accordance with GAAP. Enterprise Value The Company’s enterprise value is calculated as total market capitalization plus net debt. Enterprise value is used to assess the valuation of the Company. Refer to the Liquidity and Capital Resources section in the MD&A for the quarter ended June 30, 2026 for further information. Net Debt Net debt is a key capital management measure as it is used to assess the ongoing liquidity of the Company. Net Debt is calculated as the carrying value of the Senior Notes, less adjusted working capital including cash. The Company closely monitors its capital structure with a goal of maintaining a strong balance sheet to fund the future growth of the Company. Net Debt to Adjusted EBITDA Management considers Net Debt to Adjusted EBITDA an important measure as it is a key metric to identify the Company’s ability to fund financing expenses, net debt reductions and other obligations. When this measure is presented quarterly, Adjusted EBITDA is annualized by multiplying by four. When this measure is presented on a trailing twelve-month basis, Adjusted EBITDA for the twelve months preceding the net debt date is used in the calculation. Net Debt to Adjusted EBITDA is calculated as Net Debt divided by annualized Adjusted EBITDA. Net Operating Expenses and Net Operating Expenses per BOE Net operating expense is calculated by deducting processing income primarily generated by processing third party production at processing facilities where the Company has an ownership interest, from operating expenses presented on the Statement of income (loss). Where the Company has excess capacity at one of its facilities, it will process third-party volumes to reduce the cost of ownership in the facility. The Company’s primary business activities are not that of a midstream entity whose activities are focused on earning processing and other infrastructure-based revenues, and as such third-party processing revenue is netted against operating expenses in the MD&A. This metric is used by management to evaluate the Company’s net operating expenses on a unit of production basis. Net operating expense per boe is a non-GAAP financial ratio and is calculated as net operating expense divided by total barrels of oil equivalent produced over a specific period of time. The calculation of the Company’s net operating expenses is shown within the net operating expenses section within the MD&A for the quarter ended June 30, 2026. Operating Netback and Operating Netback, Net of Derivatives The Company’s operating netback is determined by deducting royalties, net operating expenses and transportation expenses from petroleum and natural gas sales. The Company’s operating netback, net of derivatives is calculated by adding or deducting realized financial derivative commodity contract gains or losses from the operating netback. Derivative contract termination payments are included in realized derivative commodity contract gains or losses for the purposes of calculating the operating netback. The Company’s operating netback and operating netback, net of derivatives are used in operational and capital allocation decisions. Presenting operating netback and operating netback, net of derivatives on a per boe basis is a non-GAAP financial ratio and allows management to better analyze performance against prior periods on a per unit of production basis. Supplemental Information Regarding Product Types References to gas or natural gas and NGLs in this presentation refer to conventional natural gas and natural gas liquids product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities, except where specifically noted otherwise. Q2 2026, Q1 2026, Q4 2025 and full year 2025 average production volumes, respectively, were comprised of 64, 64%, 64% and 65% light & medium crude oil; 8%, 7%, 8% and 8% Heavy crude oil; 9% NGLs for all periods; and 18%, 19%, 19% and 18% natural gas. Q3 2026 forecast production at midpoint is anticipated to be comprised of ~65% light and medium crude oil, ~7% heavy oil, 9% NGLs & 18% natural gas. Disclaimer Oil & Gas Advisories
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 36 Type Curve Certain type curve disclosure presented herein represents estimates of the production decline and ultimate volumes expected to be recovered over time. “Results Projected” are based on a forward estimate of ultimate volumes to be recovered over time based on the initial 30 days average production data. “Guidance Well Type Curves” are the forecasted well performance used in setting the Company’s guidance for expected results of the drilling program. Projected Results and Type Curves are useful in confirming and assessing the potential for the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter, are not necessarily indicative of long-term performance or of long-term economics of the relevant well or fields, including future wells to be drilled, or of ultimate recovery of hydrocarbons. Boe Presentation 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. Initial Production Rates Initial production (“IP”) rates disclosed herein, particularly those of short duration, may not necessarily be indicative of long-term performance or of ultimate recovery. Initial Production ("IP") rates indicate the average daily production over the indicated daily period. FD&A Expenditures The Company uses finding, development, and acquisition (FD&A) expenditures as a basis to monitor its capital efficiency. The Company’s FD&A expenditures are calculated by adding A&D to capital expenditures less certain capitalized overhead costs. This measure calculates the capital cost outlay associated with the Company’s exploration and development activities for the purposes of finding, developing and, when desired, acquiring its reserves. Disclaimer Oil & Gas Advisories
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 37 Oil and Gas Metrics & Reserve Definitions This presentation contains metrics commonly used in the oil and gas industry which have been prepared by management, such as “FD&A costs”, “Net Asset Value”, “Recycle Ratio” and “Reserve Life Index”. 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. Disclaimer Oil & Gas Advisories "FD&A Cost" represents finding, developing and acquisition cost as calculated as the sum of 2025 capital expenditures not including capitalized general and administration expenses ($232.7 million) plus net acquisition costs ($93.8 million), divided by the change in reserves within the applicable reserves category. “Net Asset Value” has been calculated based on the estimated net present value of all future revenue from the Company’s reserves, before income taxes as estimated by Ryder Scott effective December 31, 2025, including expenditures for abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities, less net debt. “Recycle Ratio” is calculated by dividing operating netback per boe by FD&A costs or F&D costs for a year. “Reserve life index” or “RLI” is calculated by dividing the applicable reserves category volumes by 2025 fourth quarter production of 43,657 boe/d for 365 days as an estimation of how many years at a steady production level would the reserve volumes support. “Production Replacement” is calculated by dividing reserves added by annual production, expressed as a percentage and shown by reserve category. "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. "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 (e.g. when compared to the cost of drilling a well) to put the reserves on production. "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, possible) to which they are assigned. Reserve Assumptions: Reserve evaluation calculations are based on data and expected future production volumes as provided by third party independent evaluators Ryder Scott Company (the “Ryder Scott Report”) for year end December 31, 2025. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Corporation’s reserves estimated in The Ryder Scott Report represent the fair market value of those reserves. “Identified Inventory”: This presentation discloses “Booked” proved and probable drilling locations of the Ryder Scott Report for a total of 1,205 gross booked drilling locations. Further information of the location of the Booked drilling locations is listed in Saturn’s news release dated March 11, 2026. An additional approximately 1,400 locations have been internally identified and are unbooked. Burgess Creek drilling locations are based on internal estimates and updates to its 3rd party reserve evaluators’ independent evaluation, with an effective date of March 31, 2026, and include 117 gross (113.1 net) booked locations. An additional approximately 216 gross locations (212.1 net) locations have been internally identified and are unbooked. “Un-booked drilling locations” are based on Saturn’s management review of its current land assets, geological and reservoir parameters that support potential economic development and do not have attributed reserves or resources. .
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S AT U R N O I L + G AS | C O R P O R A T E P R E S E N T A T I O N T S X: S O I L | O T C Q X: O I L S F 38 Oil & Gas Advisories SUPPLEMENTAL INFORMATION REGARDING CORPORATE RESERVES (1) Light and Medium Crude Oil (Mbbl) Heavy Crude Oil (Mbbl) Conventional Natural Gas (MMscf) Natural Gas Liquids (Mbbl) Total MBOE (Mboe) Reserves Category Gross Net Gross Net Gross Net Gross Net Gross Net Proved Developed Producing 58,263 53,786 10,312 8,785 104,631 95,276 8,387 7,630 94,400 86,081 Non-Producing 366 350 9 9 149 144 32 31 431 414 Undeveloped 34,185 31,541 1,100 1,058 61,631 55,206 3,665 3,307 49,221 45,107 Total Proved 92,813 85,676 11,421 9,853 166,411 150,626 12,084 10,968 144,053 131,602 Probable 49,394 45,439 4,951 4,219 91,491 81,792 5,985 5,290 75,579 68,580 Total Proved Plus Probable 142,207 131,115 16,372 14,071 257,902 232,418 18,068 16,259 219,631 200,182 SUPPLEMENTAL INFORMATION REGARDING CORPORATE RESERVES VALUES (1)(2) 0% Discount 5% Discount 10% Discount 15% Discount 20% Discount Reserves Category MM$ MM$ MM$ MM$ MM$ Proved Developed Producing 2,179.5 2,074.8 1,768.0 1,517.4 1,327.5 Non-Producing 15.5 11.0 8.1 6.1 4.7 Undeveloped 1,097.7 663.9 411.9 256.3 155.1 Total Proved 3,292.7 2,749.7 2,187.9 1,779.8 1,487.4 Probable 2,579.0 1,487.3 962.3 673.4 498.7 Total Proved + Probable 5,871.7 4,237.0 3,150.3 2,453.2 1,986.1 Disclaimer 1) The estimated NPV does not represent fair market value of the reserves. 2) Price forecasts and foreign exchange rate assumptions of three consultant’s (GLJ Ltd., McDaniel & Associates Consultants Ltd. and Sproule Associates Ltd.) average forecast as of January 1, 2026 as applied in the Ryder Scott Report.