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TSX: TVE Oct. 2026 Q3 2026 Update + Merger Presentation West Marten 15-15 Battery Facility 15-15-076-05W5 CREATING SUSTAINABLE VALUE
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1 Tamarack Q3 2026 Update
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2 Q3 2026 Highlights Robust Operational Execution, Elevated Commodity Prices and All-Stock Headwater Merger (Expected T o Close November 18) 1) See “Specified Financial Measures”. 2) Production of 55,298 boe/d: 50,500 bbl/d heavy oil, 665 bbl/d NGL, 24,800 Mcf/d natural gas. • Entered into a combination with Headwater on Sept 7, 2026, adding ~25,000 boe/d of high-margin oil production, >100 MMboe of P+P reserves, and >1,000 drilling locations across the Clearwater fairway1 • Q3/26 Clearwater assets delivered 55.3 Mboe/d2, a 16% increase over Q3 2025 • Current Clearwater waterflood injection of >60,000 bbl/d with an anticipated exit rate of ~70,000 bbl/d by 2026YE (TVE standalone assets); Combined company exit water injection rate >100,000 bbl/d • Generated $214 MM of adjusted funds flow and $92 MM of free funds flow ($0.19 / diluted share) • Returned $85.3 MM to shareholders through share buybacks and base dividends in Q3 • Repurchased 4.6 MM common shares (~0.9% of float) for $61.7 MM • Paid $23.6 MM of dividends; current base dividend of $0.20/Sh. (increased by 25%) • Net cash position of $141.2 MM in Q3/26 ($541.4 MM of cash on balance sheet) $631 $(141) 0.6x -0.1x -0.4x -0.2x 0.0x 0.2x 0.4x 0.6x 0.8x -$400 -$200 $0 $200 $400 $600 $800 Q3 2025 Q3 2026 Net Debt ($MM) & Net Debt / LTM EBITDA (x)1 Net Debt Net Debt / LTM EBITDA 47.8 55.3 40 45 50 55 60 Q3 2025 Q3 2026 Production (Mboe/d) Clearwater Production (Mboe/d)1,2 ~$541 MM of Cash On Balance Sheet $37.8 $61.7 $18.9 $23.6 $56.7 $85.3 $0 $20 $40 $60 $80 $100 Q3 2025 Q3 2026 Return of Capital ($MM)1 Share Buybacks Base Dividends
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3 Demonstrated Value Creation Compounding Success on a Per Share Basis 1) “Cash Return On Capital Invested” calculated as debt-adjusted cash flow from operations (before working capital changes) divided by capital invested. Capital invested calculated as total assets, plus accumulated DD&A, minus cash and cash equivalents, minus non-interest-bearing current liabilities. WACC assumes a 5% ERP and average yield on US 10-year as a risk-free rate. 2026 YTD cash flow is annualized. Repurchased ~15.4% of 2023YE Share Count to Date (as at Q3 2026) at Average Cost of ~$5.80/Sh. 3 Q3/26 Net Cash Position of ~$141 MM (~$541 MM Cash on Balance Sheet) Significant Debt Adj. Per Share Value Growth From Operational Outperformance, Long-Term Buybacks, and Debt Repayment 2) Debt adjusted using a Tamarack share price of $13.50/Sh. Quarterly DAPPS and debt adj. FFO per share amounts use average net debts and weighted average common share counts during the quarter. 3) Change in common share count from Dec. 31, 2023, to Sep. 30, 2026. $20 $30 $40 $50 $60 $70 $80 $90 $100 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40 $0.45 $0.50 $0.55 Q4-22 Q1-23 Q2-23 Q3-23 Q4-23 Q1-24 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Q3-25 Q4-25 Q1-26 Q2-26 Q3-26 Average WTI Price (US$/bbl) Adj. Funds Flow Per D.A. Share ($/D.A. Share) Adj. Funds Flow Per Debt Adj. Share ($/Sh.)2 Adj. Funds Flow Per Debt Adj. Share Average WTI Price 80 90 100 110 120 130 140 Q4-22 Q1-23 Q2-23 Q3-23 Q4-23 Q1-24 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Q3-25 Q4-25 Q1-26 Q2-26 Q3-26 DAPPS (boe/d/MM Debt Adj. Shares) Debt Adjusted Prod. Per Share ("DAPPS")2 $20 $30 $40 $50 $60 $70 $80 $90 $100 0% 5% 10% 15% 20% 25% 30% 2021 2022 2023 2024 2025 2026 YTD Average WTI Price (US$/bbl) CROCI vs. WACC (%) CROCI vs. WACC (%)1 WACC CROCI - WACC Spread CROCI Average WTI Price Charlie Lake Disposition +50%+20%
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4 Budget WTI (US$/bbl) $60.00 WTI / WCS Diff (US$/bbl) ($12.75) WCS (C$/bbl) $63.79 AECO ($/GJ) $2.75 FX (US$/C$) 1.35 2026 Annual Guidance Original Guidance (Dec. 2025) Current Guidance (Sep. 2026) Tamarack Clearwater Assets ($MM) $385 - $405 Acquired Headwater Assets (Close Mid Q4/26; $MM) $20 Divested Charlie Lake Assets (Sold Q2/26; $MM) $45 2026 Total Capital1 ($MM) $390 – $410 $450 – $470 Tamarack Clearwater Assets (boe/d) 54,500 – 56,000 Acquired Headwater Assets (Close Mid Q4/26; boe/d) 3,000 – 3,500 Divested Tamarack Charlie Lake Assets (Sold Q2/26; boe/d) 8,000 Total Production (boe/d) 69,000 – 71,000 65,500 – 67,500 Average Oil & NGLs (%) 84% – 86% 88% – 90% Royalty Rate (%) 19% – 21% 20% – 22% Wellhead Oil Price Differential2 ($/bbl) $1.00 – $1.50 $0.75 – $1.25 Net Operating Expense3 ($/boe) $6.85 – $7.15 $6.65 – $6.90 Transportation Expense ($/boe) $4.00 – $4.50 $4.00 – $4.50 G&A Expense ($/boe) $1.30 – $1.45 $1.40 – $1.55 Interest Expense4 ($/boe) $2.70 – $3.10 $2.00 – $2.40 Income Tax Expense (% of B-Tax Adj. Funds Flow) 10% – 12% 17% – 19% Reaffirming 2026 Corporate Guidance 1) Excludes ARO. 2) Oil wellhead deductions for grade specific trading differential (ex. CHV), blending requirements, quality differential, and pipeline tolls if TVE is not marketing (lease transactions). Pure Play Clearwater Company Geared For Incremental Growth & Returns 3) Includes CIP fee for service and minimal carbon tax budgeted. 4) Includes CIP ToP capital fee. Forecast Clearwater Annual Production Growth of ~23% YoY (Organically ~16%) While Lowering Declines And Reinvestment Requirements Expected 2026 Exit Water Injection of >100,000 bbl/d on a Combined Basis ~45% of Production Supported by Waterflood Focused Delineation Primary and Enhanced Oil Recovery Across The Greater Clearwater Fairway & Pelican Region Full Year 2026 Capital Guidance of $450 MM – $470 MM Reflecting Incremental Spending Associated With Headwater’s Planned Capital Program Combined 2027 Budget to be Announced in Conjunction with the Transaction Close (Shareholder Vote November 18, 2026)
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5 0 5 10 15 Jan-24 Jul-24 Jan-25 Jul-25 Jan-26 Jul-26 Oil Production Under Waterflood (Mbbl/d) Clearwater Waterflood - Oil Under Flood By Vintage (Mbbl/d)1 As at Jan. 1, 2024 As at Jan. 1, 2025 As at Jan. 1, 2026 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 2022/12 2023/12 2024/12 2025/12 2026/12 Oil Under Waterflood (%) Water Injection (bbl/d) Water Injection (bbl/d) % Oil Under Waterflood Tamarack Clearwater Waterflood Progression (Existing TVE Assets) Advancing Secondary Recovery To Drive Incremental Resource Capture ~40% of Clearwater Oil Production Under Waterflood by YE 2026 EUR’s Up To 3x Primary Recovery Demonstrated waterflood success at highly attractive F&D costs Mitigating Decline Reduces sustaining capital requirements Demonstrated Repeatability Positive waterflood responses across multiple sands, areas, and well designs Forecast Clearwater Injection & Production Under Waterflood 2024 Vintage Avg: ~2.4 Mbbl/d Growth: ~58%1 2025 Vintage Avg: ~4.8 Mbbl/d Growth ~55%1 2026 YTD: ~12.9 Mbbl/d Growth ~34%1 1) Average production by vintage is the average production from wells in the onstream date to the end of the data series. Growth from start to finish is from the vintage onstream date to the end of the data series (i.e., 2024 vintage growth measured from Jan. 1, 2024, to Oct. 20, 2026). >200% Waterflood TPP Reserve Volume Growth (‘25YE / ’24YE) Exit 2026 Water Injection Rate Expected To Be ~16% Above 2026 Budget Expanding The Boundaries South Clearwater pilots; Pelican & Seal enhanced recovery simulation; targeted evaluation of thermal opportunities All metrics on this page are for Tamarack standalone (excl. HWX).
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6 0 10 20 30 40 50 60 70 80 Jul-24 Dec-24 May-25 Oct-25 Mar-26 Aug-26 Jan-27 Jun-27 Nov-27 Oil Production (bbl/d) Actuals Internal Primary Forecast Start of Injection Prolific Waterflood Performance (Existing TVE Assets) • Waterflood response from two producers offsetting 100/08-13-063-22W4/0 pilot injector exhibiting >100% incremental oil relative to primary baseline • Strong positive indication for waterflood upside in the Southern Clearwater fairway as water cuts remain unchanged relative to primary production Secondary Recovery Redefining Production Potential Meanook Waterflood PilotClearwater Producers Under Flood at YE 2025 (Actuals vs. 2025 Year End P+PDP Reserves2) • Strong waterflood performance is reducing corporate decline, driving lower sustaining capital requirements and improved growth efficiency • Reserves added broadly every year the waterflood outperforms • Injector conversions generating incremental oil recovery at an F&D of <$1.00/bbl1 F&D = Finding & Development Costs. See “Disclaimers – Oil & Gas Metrics”. 1) F&D calculated using management estimates of incremental oil recovery associated with secondary recovery vs. primary recovery for all wells under waterflood at YE 2025, capital cost assumes $0.4 MM per injector conversion 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 Oil Rate (bbl/d) Cumulative Oil (Mbbl) Actuals YE 2025 P+PDP Reserves 2) Clearwater producers under waterflood P+PDP oil forecast as at 2025 YE. P+PDP = Proved plus probable developed reserves. See Disclaimers – Oil & Gas Metrics Waterflood Ramp
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7 Strategic Combination of Tamarack Valley Energy and Headwater Exploration Creating a Premier North American Oil Producer
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8 Combined Land Position Transaction Overview Tamarack Valley (TVE) and Headwater Exploration (HWX) to Merge in All-Stock Transaction • HWX shareholders to receive 1.0 TVE share per HWX share • Pro forma ownership 66.5% TVE | 33.5% HWX Creates Largest Clearwater Producer and Premier North American Oil Producer • >80,000 boe/d of low-decline production with significant asset duration • Consolidates core areas of Marten Hills, Nipisi, and West Marten Hills, as well as more than doubles Tamarack’s land holdings at Pelican and Seal Unique Shared Upside in Newly Formed Tributary Exploration • Certain Mannville rights, prospective thermal heavy oil opportunities at Handel, Saskatchewan, and McCully gas production in New Brunswick • Tributary will be operated by Headwater’s current management team; seeking a public listing in conjunction with private placement equity financing • Basic ownership 66.5% TVE | 33.5% HWX before equity financing and dilutives Tamarack Valley and Headwater Exploration Announce Strategic Combination Valued at ~$10 Bln R18W3 Seal Dawson Nipisi Marten Hills Canal Jarvie Perryvale Meanook Marten Hills West Tamarack Land Headwater Land Duncan Craigend R25R1W5 R15R20R5 T75 T70 T65 T58 R8W4 Peavine West Nipisi Utikuma R10R10R15 Pelican Clay T60 T80 Sugden T34 T35 T36 T37 Handel Tributary Exploration Lands Pro Forma Metric Units Enterprise Value $Bln ~$6 ~$4 ~$10 Production Mboe/d > 55 > 25 > 80 Clearwater Land Net Sections 900 650 > 1,500 Clearwater Locations # > 2,000 > 1,000 > 3,000 2027 Decline Rate % 15% As Press Released Sep. 7, 2026
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9 Key Governance Elements of the Combined Company Leadership Board of Directors Expected Ownership at Close Support Agreements Lock Up Restrictions • Merger completed through a plan of arrangement in respect of the shares of TVE and HWX and is subject to the approval of at least two-thirds of the votes cast by both companies • Shareholder meetings (plan of arrangement approval requires two thirds or 66.67% majority of respective shareholders of TVE & HWX) • The combined company will be led by Tamarack’s management team, including the following changes (effective January 1, 2027): • Steve Buytels as President & Chief Executive Officer and Brian Schmidt as Executive Chairman • Tamarack and Tributary Exploration will operate independently, with Tributary led by current executives of Headwater • Tamarack’s Board will be expanded at Close and consist of: • Tamaracks current Board plus the addition of Steve Buytels, President & CEO (effective January 1, 2027) • Two Headwater directors mutually agreed by Tamarack and Headwater o Jason Jaskela, President and CEO of Headwater plus one other individual • Estimated pro forma ownership 66.5% TVE | 33.5% HWX Arrangement Agreement / Voting • All directors and officers of Headwater (~6% ownership) and Tamarack (~2% ownership), have entered into support agreements pursuant to which they have agreed to vote in favour of the Transaction • Tamarack shares issued to directors and officers of Headwater will be subject to a hold period and released in thirds at 3 months, 6 months, and 9 months following the Closing Date
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10 Premier North American Oil Producer Low Breakeven; High Margin Higher Profitability: ~US$37/bbl WTI Breakeven • Lower Decline Rate to 12% at End of 5-Year Plan • Lower Unit Operating, Transport, and G&A Costs • Sustaining Reinvestment Ratio of <20%1 Cash Position With Substantial Liquidity Flexibility To Be Opportunistic • ~$50 MM Net Cash Position at Close (Mid November) • ~$1.3 Bln of Available Funding Significant Asset Duration Decades of Drilling & Waterflood Inventory • Largest Depth of Highly Consolidated Clearwater Drilling Inventory in the Heart of the Fairway2 • >18 Billion Barrels of Original Oil in Place • Greater Exposure to Grand Rapids & Wabiskaw Targets Resilient Free Funds Flow Drives Returns • Increased Annual Dividend by 20% to $0.24/Sh. • Pro Forma Annual Production Growth Rate of 10% - 12% (vs. 8% - 10% prior) Increasing Shareholder Returns Differentiated Market Leader: Top-Decile Economics & The Only Public Pure-Play Clearwater Producer Largest Clearwater Producer | ~$10 Bln Enterprise Value • >80,000 boe/d Run-Rate Production • >1,500 Sections in the Clearwater Fairway • >3,000 Identified Primary Drilling Locations See Disclaimers – “Specified Financial Measures”. 1) Average for 2027E to 2030E at US$75/bbl. 2) Source: Enverus Intelligence Research, February 2026. Meaningful Synergy Capture >$50 MM/Yr. & >$350 MM B-Tax NPV-10% • Integration of Operations, Marketing and Corporate Offices • Near-Term Synergies Through Consolidation & Streamlining Development Starting in 2027 Better Together: Profitability, Duration, & Returns Benefits to Shareholders All-Equity Combination Accretive to Financial and Operating Metrics Accretive FCF Metrics & Upside Participation In Exploration Assets • Immediately Accretive to Free Funds Flow per Share >10% & Existing Five-Year Plan • Continued Upside Participation in Emerging Exploration Through Tributary Exploration
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11 Perfect Fit: Tangible Synergies Netback Improvement More Efficient Investment Lower Corporate Costs Infrastructure Utilization & Transport • Operating and transport synergies from higher volumes, increased pipeline utilization, and lower unit costs • Marketing synergies with dedicated in-house marketing team, favourable contracts, and additional firm capacity • Infrastructure optimization and overall development efficiencies • Multi-zone co-development on larger pads • Lower delineation capital and overhead costs • Reduction of head office and executive costs • Enhanced size and scale improves credit profile and lowers cost of capital >$15 MM >$15 MM >$20 MM Near-Term Synergies (B-Tax) • Optimized capital program and waterflood infrastructure in consolidated areas • Utilize existing overlapping infrastructure in emerging areas • Egress economies of scale for Pelican & Seal Additional Long-Term Synergies 1) Based on PV-10% before tax. Annual Immediate Synergies Through Integration of Operations & Streamlining Development Programs R3R5 R25R1W5R7 T77 T75 T73 T69 R23W4 T71 T79 T81 T83 R11R13 R9R15 Tamarack Land Headwater Land Near-Term Synergy Areas Significant Annual Near-Term Synergies of >$50 MM per year | >$350 MM1 of Total Value Over the Plan Seal Marten Hills Marten Hills West Pelican West Nipisi Synergies Are Trending Higher; Update To Be Provided With 2027 Budget
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12 Differentiating Tamarack: Asset Scale & Economic Scope Top Tier Assets With Large OOIP1 • >18 billion barrels of OOIP (Clearwater, Grand Rapids and Bluesky/Wabiskaw); <2% of OOIP produced by end of 5 Yr. Plan • Proven Clearwater waterflood driving incremental resource capture and duration • Long runway of high-quality drilling inventory: >3,000 locations (100 - 150 wells per year) High Growth With Lowering Declines • Unique ability to grow production 10% - 12% and reduce decline rates with continued waterflood implementation Low Sustaining Cost & Resilient Breakeven Price • Unhedged breakeven <US$37/bbl WTI covering maintenance capital + dividend Regional Basin Egress Commitments Matches Growth Plans • Across several terminals and pipelines, the combined entity holds egress for the development plan Capital Allocation Optionality • Focused on assets and capital allocation to generate the highest return ON capital, to allow the highest return OF capital Highly Economic Full-Cycle Returns = Free Funds Flow Growth See Disclaimers – “Specified Financial Measures”. 1) OOIP – original oil in place based on internal estimates. 2) Large-cap sustaining capital ratio estimates per Peters & Co. Calculated as sustaining capital to maintain flat production / adj. funds flow on Oct. 19 strip. Peer group includes AR, CNQ, DVN, EOG, EQT, EXE, FANG, IMO, OVV, SCR, SU, TOU, and WCP. Pro forma TVE $600 MM capital case assumed. 3) Large-cap total return CAGR’s from 2027-2031 at forward strip pricing. TVE total return CAGR from 2027-2031 at forward strip pricing. Peer group includes AR, CNQ, DVN, EOG, EQT, EXE, FANG, IMO, OVV, SCR, SU, TOU, and WCP. Peer data per Peters & Co. as at Oct. 19, 2026. -0.25x 0.00x 0.25x 0.50x 0.75x 1.00x 1.25x 0% 5% 10% 15% 20% Peer 1 Peer 3 Peer 6 Peer 2 Peer 9 Peer 12 Peer 8 Peer 13 Peer 4 Peer 10 TVE Pro Forma Peer 11 Peer 7 Peer 5 Large-Cap Peers: Total Return CAGRs vs. 2027E Net Debt / LTM Funds Flow (%; x)3 TVE Pro Forma Capex $600 - $650 Large-Cap Peer Average 2027YE Net Debt / LTM Funds Flow Pro Forma Above Average Returns With No Debt 0% 10% 20% 30% 40% 50% 60% Peer 1 TVE Pro Forma Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 2027E Large-Cap Peers: Sustaining Reinvestment Ratio (%)2
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13 0 5 10 15 20 25 Jan-24 Jul-24 Jan-25 Jul-25 Jan-26 Jul-26 Pro Forma Oil Under Waterflood By Vintage (Mbbl/d)2 As at Jan. 1, 2024 As at Jan. 1, 2025 As at Jan. 1, 2026 36% 6.7 33% 6.0 1% 0.2 5% 0.8 16% 2.9 9% 1.7 Marten Hills Nipisi and W. Marten Canal Pelican Greater Seal S. Clearwater Decades of Asset Duration OOIP Scale and Recovery Enhancement Driving Asset Duration >18 Billion Barrels OOIP1 1) OOIP – original oil in place based on internal estimates. 2) As at Oct. 20, 2026. Production for each vintage is for producing wells as of each date. 3) Data as per Company Filings. FD&A costs used for recycle ratio in cases where F&D costs undisclosed. Peer Group includes BTE, IPO, KEL, OBE, RBY, SCR, SDE, SGY, VET, and WCP. >70% of OOIP1 in Areas With Demonstrated Secondary Recovery 1.1x1.1x1.3x1.4x1.7x1.8x1.8x1.8x2.0x2.5x 4.1x 5.2x 0x 1x 2x 3x 4x 5x 6x Peer 10Peer 9Peer 8Peer 7Peer 6Peer 5Peer 4Peer 3Peer 2Peer 1HWXTVE • <2% recovered over five-year plan, decades of duration • >3,000 primary locations (100-150 wells per year) • Successful secondary recovery expanding in Grand Rapids and Wabiskaw • Advancing thermal opportunity through assessment and pilot execution 2025A Public Peer Recycle Ratios (PDP; x)3 OOIP by Area1 >45% Under Flood at YE 2026 EOR Assessment, Planned and Active Pilots
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14 20% 15% 34% 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 PF TVE Peer #1 HWX Peer #2 Peer #3 Peer #4 Peer #5 Peer #6 Peer #7 Peer #8 Net Clearwater Acreage Existing Waterflood Footprint 0-1000 1000-2000 2000-3000 3000-4000 4000+ Unproven (cP)Waterflood Potential (cP) Enhanced Scale & Depth of Quality Inventory + Waterflood Acreage 0 200 400 600 800 1000 1200 1400 1600 1800 PF TVE Peer #1 HWX Peer #2 Peer #3 Peer #4 Peer #5 Peer #6 Peer #7 Peer #8 Net Location Count Normalized to 30,000' of Lateral 1) Clearwater Operator Primary Well Inventory per Enverus Intelligence Research (Feb. 2026). Peer group includes BTE, CNQ, ISH Energy, Longridge, OBE, RBY, Spur, and Woodcote. Tamarack pro forma is the sum of Tamarack and Headwater standalone. 2) Clearwater Waterflood Acres by Operator per Enverus Intelligence Research (Feb. 2026). All acreage shown in waterflood potential and additional lands lie within 3/4 mile of commercial well production. Tamarack pro forma is the sum of Tamarack and Headwater standalone. % of land already under waterflood is a weighted average. % of <3,000 cP Lands Already Under Waterflood “Tamarack has a distinct advantage since it holds the largest remaining waterflood potential acreage…” Enverus Intelligence Research | February 23, 2026 Pro Forma Pro Forma Industry Leading Clearwater Inventory & Duration With Waterflood TVE Pro Forma Holds 82% More Locations Than the Next Clearwater Producer and 101% More Than Peers #2-#8 Combined Clearwater Operator Primary Well Inventory1 Clearwater Waterflood Acres by Operator2
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15 Tamarack Egress Update Strong Transportation Commitments to Guarantee Industry-Leading Netbacks Tamarack Has Secured 35,000 bbl/d of Long-Term Egress out of Alberta • 25,000 bbl/d of TMX service to the West Coast expected to commence Q1 2027, subject to the completion of the Drag Reducing Agent (DRA) expansion • 10,000 bbl/d of capacity on the proposed South Bow Prairie Connector pipeline potentially starting by 2028YE (pending approval and construction) Combined Clearwater Commitments Provides Local Egress • Apportionment-protected pipeline commitments on Plains Rainbow and Pembina Nipisi system covers the 5-year development plan 1 2 Pipe Commitments Provide TVE Opportunity to Mitigate Risk of Capacity Constraints and Obtain Exposure to Diversified Oil Markets Over the Long Term
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16 $0.100 $0.120 $0.150 $0.153 $0.160 $0.200 $0.240 $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 Oct. 2021 Apr. 2022 Sep. 2022 Oct. 2024 Oct. 2025 May 2026 Sep. 2026 Tamarack Annualized Dividend per Share ($/Sh.) On Announcement Date Return of Capital Exceptional Record of Shareholder Returns • Since inception of the dividend in 2022, it has increased six times for cumulative growth of ~140% • Initiated share repurchases under a NCIB program in 2024, repurchased 15.4% of 2023YE common share count to date at an average share price of $5.80/sh.1 Tamarack’s Return of Capital Strategy is Built on a Foundation of Sustainable and Growing Base Dividend Plus Share Repurchases • Enhanced scale, stronger base declines and free cash flow durability supports a further 20% dividend increase to $0.24/Share (annualized) • Base dividend supported by lower breakeven of ~$37/bbl WTI (unhedged) • Allocating additional free funds flow to share buybacks while maintaining flexibility and optionality +20% +25% +2% +5% +25% +20% 1) 2026 YTD up to and including September 2026 (includes Q3/2026 dividend declaration). % of share count repurchased is calculated using the 2023YE common share count. >$850 MM of Direct Shareholder Returns Since 2022 2026 YTD (To Q3/26) $81 $77 $62 $359 $135 $185 $189 $510 $55 $84 $217 $262 $251 $869 6.1% 12.6% 15.4% 15.4% -20% -16% -12% -8% -4% 0% 4% 8% 12% 16% $0 $200 $400 $600 $800 $1,000 2022 2023 2024 2025 2026 YTD Total Tamarack Return of Capital History1 Share Buybacks ($MM) Base Dividends ($MM) Cumulative % of 2023YE Share Count Repurchased (%)
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17 0 10 20 30 40 50 60 70 80 90 100 110 120 130 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 2023A 2024A 2025A 2026E Pro Forma 2027E 2028E 2029E 2030E Annual Production (Mboe/d) Annual Capex ($MM) 2027E-2030E Capital (Excl. Sust. Capital and Waterflood) Growth / Derisk / Other Capital ($MM) Waterflood Capital ($MM) Sustaining Capital ($MM) Annual Average Production 15% ~12% 0% 10% 20% 30% 40% 50% 60% 0% 5% 10% 15% 20% 25% 30% 35% 40% 2023A 2024A 2025A 2026E Pro Forma 2027E 2028E 2029E 2030E Sustaining Reinvestment Ratio (%) Annual CorportateBase Decline Rate (%) Annual Corporate Base Decline Rate & Sustaining Capital (%; $MM)2 Preliminary Pro Forma Long-Term Plan 2 Growth Through High Margin Clearwater Barrels Annual Capital of $600 MM - $650 MM Sustaining Reinvestment Ratio (% / Yr.)2 Corporate Base Decline (% / Yr.) Historical Historical Annual Corporate Base Decline & Sustaining Reinvestment Ratio(%)3Long-Term Plan Capex & Production ($MM & Mboe/d) Tamarack has the Unique Ability to Grow Production and Reduce Decline Rates Simultaneously 1) See Disclaimers – “Specified Financial Measures”. 2) Sustaining capital includes well drill, complete, equip and tie-in including infrastructure required to support development to hold production flat and minimum annual ARO spending. Waterflood Has Materially Reduced Base Decline Rates & Sustaining Capital Requirements1,2 • Production growth of 10% - 12% per year, growing to 110+ Mboe/d by 2030E • Analysis assumes a capital range of $600 MM to $650 MM per year • Average capex / funds flow reinvestment of ~40% from 2027E-2030E with optionality for higher growth; sustaining capital of <20% of funds flow (US$75/bbl WTI) LT Plan to be Refined With 2027 Budget 10% – 12% Annual Growth vs. 8% – 10% Under Prior Plan Decline Rates Trending From ~15% to ~12% by 2030E (Previously ~18% to ~15% By 2030E) Emerging Exploration Area Development Currently Outside the 5-Year Plan & Offer Additional Upside Average Sustaining Reinvestment Ratio of ~20% from 2027E-2030E Pro Forma Run-Rate 3) Based on $600MM Annual Capital Program assuming US$75 WTI Flat for 2027E to 2030E. Sustaining reinvestment ratio calculated as sustaining capital / adjusted funds flow.
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18 70% - 80% 80% - 90% 90% - 100% 0% 20% 40% 60% 80% 100% US$55/bbl US$65/bbl US$75/bbl Pro Forma Cumulative 5 Year Total Shareholder Return (2026E-2030E; %)1,3 Pro Forma Ranges Midpoint of Prior Plan 10% - 12% 12% - 14% 13% - 15% 14% - 16% 6% 8% 10% 12% 14% 16% 18% 2027 2028 2029 2030 Pro Forma Discretionary Free Funds Flow Yields (US$75/bbl; % of Current Enterprise Value)1,2 Pro Forma Ranges Midpoint of Prior Plan Improved, Compounding Per Share Returns Pro Forma Cumulative Total Shareholder Return (2026E-2030E; %)1,3 Pro Forma Discretionary Free Funds Flow Yields Range (US$75/bbl; % of Current Enterprise Value)1,2 Production Growth + Lower Sustaining Capital + Share Buybacks + Excess Cash Flow = Outsized Per Share Returns 1) See Disclaimers – “Specified Financial Measures”. Disc. FFF yield assumes enterprise value of ~$10 Bln. Total shareholder return assumes market capitalization of ~$10 Bln. All flat decks assume 1.30 US$/C$. The Prior Plan has been normalized for share price. 2) Discretionary free funds flow is adj. funds flow – sustaining capital required to hold production flat, for each given year price. 3) Assumes run-rate annual dividend ($MM) is flat. Assumes shares repurchased at $13.50/Sh. Return from share buybacks is % of pro forma share count repurchased. Return from debt repayment is change in debt relative to current market capitalization. Return from production growth does not include growth from HWX volumes added through transaction alone. The Prior Plan has been normalized for share price from $12.50 to $13.50 per share. Combination drives increased Discretionary Free Funds Flow Yield Throughout the Plan • Investment in waterflood continues to lower base decline rates & sustaining capital requirements while growing high-margin Clearwater barrels Cumulative Total Shareholder Return of 70% - 100% to 2030E (US$55/bbl – US$75/bbl, 1.30 US$/C$)3 TSR = Production Growth + Dividends + Buybacks + Excess Cash Flow (Optionality) • Merger is accretive to the 5-year plan LT Plan to be Refined With 2027 Budget 90% – 100% Cumulative Total Return (US$75/bbl WTI) vs. 85% (Mid-Point) Under Prior Plan
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19 Tamarack Shareholders to Retain Exposure to Early-Stage Assets in Tributary Led by Current Executives of Headwater $MM Wild Stream Raging River Headwater Total Equity Issued(1) $381 $588 $143 Dividends Declared – – $401 Exit Value $770(2) $1,604(3) $3,210(4) Long Track Record of Success $1 Invested in Wild Stream’s First Public Financing at $4.50 Per Share in Late 2009 and Reinvested in Each Subsequent Company Would Be Worth Approximately $152 Today(5) Pro Forma (Basic) Net Asset Value per Share ($/share) $0.42 Shares Outstanding (mm) (including Private Placement and Arrangement Warrants) 356.8 Cash(6) ($mm) $50.0 Reserves & Land Value(7) ($mm) $100.7 Proceeds from Warrants ($mm) (associated with Private Placement) Up to $30.0 Pro Forma Capitalization Value Creation Through Differentiation Tributary Asset Map Also includes the McCully Gas Asset in New Brunswick Shareholder Focus • Build per-share value while maintaining a conservative balance sheet Organic Value Creation • Convert exploration success and new play concepts into production, cash flow and sustainable full-cycle returns Execution • Use technology and operating discipline to unlock and commercialize new play development Management Team • To be led by Neil Roszell, as Executive Chair, and Jason Jaskela, as President, Chief Executive Officer & Director Base Cash Flow • McCully natural gas asset provides annual cash flow of ~$17MM Tributary Exploration
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20 Appendix
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21 Tamarack Standalone - Risk Management1 1) Hedges in place as at Oct. 26, 2026. Royalty burden based on US$70/bbl WTI & 1.35 US$/C$. 2) If the average rate for the month exceeds the call, Tamarack receives an average rate forward equivalent to the knock-in price. 3) Includes 5,000 bbl/d of “synthetic” WCS Hardisty Basis trades (WCS Houston Basis Swap + WCS Transport Trade) in Q4/2026. Enhancing Certainty With Flexibility To Capture Upside Value Oil Hedges Units Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 WTI Collars Volume bbl/d 18,500 18,000 15,000 11,500 12,000 Avg. Floor Price US$/bbl $50.00 $51.53 $53.50 $51.74 $50.00 Avg. Ceiling Price US$/bbl $78.65 $83.36 $84.00 $97.09 $102.55 Avg. Premium US$/bbl $1.64 $0.25 $0.08 WTI - WCS Hardisty Basis Swaps(3) Volume bbl/d 15,500 Avg. Fixed Price US$/bbl ($13.05) WCS Hardisty - WCS Houston Swap Volume bbl/d 2,000 Avg. Fixed Price US$/bbl ($9.55) Oil Hedges (Net of Royalties) 1 Units Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 Crude Oil Hedged With WTI Contracts % 46% 44% 36% 27% 27% Heavy Exposure Hedged With WCS Basis(3) % 38% FX Hedges Units Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 US$/C$ Collars Notational US$MM/Month $19.0 $14.0 $14.0 $19.0 $19.0 Avg. Floor Price US$/C$ 1.351 1.341 1.341 1.352 1.352 Avg. Ceiling Price US$/C$ 1.397 1.394 1.394 1.410 1.410 US$/C$ Swaps Notational US$MM/Month $8.0 $12.0 $12.0 $5.0 $5.0 Avg. Fixed Price US$/C$ 1.366 1.373 1.373 1.390 1.390 US$/C$ Variable Collars (2) Notational US$MM/Month $10.0 $14.0 $14.0 $16.0 $16.0 Avg. Floor Price US$/C$ 1.353 1.348 1.348 1.357 1.357 Avg. Ceiling Price US$/C$ 1.424 1.415 1.415 1.428 1.428 Avg. Knock-In Price US$/C$ 1.391 1.392 1.392 1.403 1.403 Natural Gas Hedges Units Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 AECO 5A Swaps Volume GJ/d 3,370 Avg. Fixed Price C$/GJ $2.74
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22 Disclaimers: Tamarack Valley Forward Looking Statements: This presentation has been prepared by Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") and contains information regarding Tamarack's results for the three and nine months ended September 30, 2026, Tamarack's 2026 guidance and operations, and the proposed business combination (the "Transaction") with Headwater Exploration Inc. ("Headwater"), which is expected to be completed in mid-November 2026, subject to the satisfaction or waiver of the conditions to closing. Unless otherwise indicated, information in this presentation relating to Tamarack's third quarter 2026 results, 2026 guidance, waterflood operations, reserves and hedging is presented on a Tamarack standalone basis and does not give effect to the Transaction. References in this cautionary statement to the "combined company" refer to Tamarack following completion of the Transaction; the forward-looking statements, assumptions and risks described below in respect of the combined company apply equally to Tamarack on a standalone basis, including if the Transaction is not completed. Certain information included in this presentation constitutes forward-looking information within the meaning of applicable Canadian securities laws relating to Tamarack, Headwater, Tributary Exploration Inc. ("Tributary Exploration") and the combined company (collectively referred to herein as "forward-looking statements"). Forward-looking statements are often, but not always, identified by the use of words such as "budget", "guidance", "outlook", "anticipate", "target", "plan", "continue", "intend", "consider", "estimate", "expect", "may", "will", "should", "could" or similar words (including negatives or grammatical variations) suggesting future outcomes. Forward-looking information in this presentation may include, but is not limited to, statements about: Tamarack's business strategy, objectives, strength and focus, including the characterization of Tamarack as a pure play Clearwater company; Tamarack's 2026 guidance, including the 2026 capital budget of $450 – $470 million, annual average production of 65,500 – 67,500 boe/d, oil and NGL weighting, royalty rate, wellhead oil price differential, net operating expense, transportation expense, general and administrative expense, interest expense and income tax expense guidance, the pricing and other assumptions underlying such guidance and the allocation of capital between Tamarack's Clearwater assets and the Headwater assets following completion of the Transaction; expected Clearwater annual production growth of approximately 23% year over year; Tamarack's waterflood development plans and the anticipated results thereof, including expected exit 2026 water injection rates of approximately 70,000 bbl/d on a Tamarack standalone basis and >100,000 bbl/d on a combined basis, the proportion of Clearwater oil production expected to be under waterflood at year-end 2026 on a standalone and a combined basis, expected estimated ultimate recoveries of up to three times primary recovery, expectations that waterflood performance will continue to mitigate corporate decline rates, reduce sustaining capital requirements and support reserves additions, and expected finding and development costs; plans for South Clearwater waterflood pilots, enhanced recovery evaluation at Pelican and Seal and the evaluation of thermal opportunities; expectations regarding future technical revisions to, and growth in, Tamarack's reserves; Tamarack's return of capital strategy, including the base dividend, future dividend increases and purchases of common shares under Tamarack's normal course issuer bid; Tamarack's egress commitments, including the anticipated commencement of Trans Mountain service in the first quarter of 2027 subject to completion of the drag reducing agent expansion, anticipated capacity on the proposed South Bow Prairie Connector pipeline by year-end 2028 subject to regulatory approval and construction, and the anticipated benefits of such commitments; Tamarack's commodity price and foreign exchange risk management program; the timing of the announcement of the combined company's 2027 budget; the business strategy, objectives, strength and focus of the combined company, including the characterization of the combined company as a premier North American oil producer with unparalleled economics; exploration and development plans and strategies of the combined company; the combined company's five-year plan and expected Clearwater growth rate; the anticipated benefits and timing for completion of the Transaction; terms of the plan of arrangement and closing of the Transaction; run-rate production, net cash and available funding of the combined company; the anticipated terms and availability of the combined company's credit facility; the integration of the businesses, assets, operations, personnel and offices of Tamarack and Headwater; the formation of Tributary Exploration and the transfer of the Tributary Exploration Assets to Tributary Exploration; accretive metrics of the combined company and expectations of higher total returns to shareholders, including free funds flow per share, corporate decline rates and free funds flow breakeven costs; the amount, timing and realization of expected synergies of the combined company; various size and scale metrics associated with the combined company, including the depth and quality of drilling inventory; the amount and composition of the combined company's proved and probable reserves; the business strategy, objectives, capitalization, financial position, operations and development plans of Tributary Exploration; the completion and terms of the Tributary Exploration Private Placement, including the pricing and anticipated gross proceeds thereof; the anticipated proceeds from the exercise of the Arrangement Warrants; the expected capitalization and working capital of Tributary Exploration; the anticipated use of Tributary Exploration's working capital; Tributary Exploration's business strategy and expected pursuit of oil weighted assets in western Canada; the anticipated dividend increase; the anticipated return of capital through dividends and share buybacks; expected balance sheet strength; the exchange ratio and the number of Tamarack common shares and Tributary Exploration common shares expected to be issued pursuant to the Transaction; the relative ownership interests of Tamarack and Headwater shareholders in the combined company and Tributary Exploration following completion of the Transaction; plans for Tributary Exploration to achieve a public listing and expectations regarding future financing and issuances of warrants; the terms of lock-up agreements with certain directors and officers of Headwater; the terms of voting support agreements entered into by directors and officers of Tamarack and Headwater; the satisfaction of the conditions to completion of the Transaction, including the receipt of required shareholder, court, regulatory and stock exchange approvals; board composition of the entities; the anticipated changes to Tamarack's leadership effective January 1, 2027, including the appointment of Steve Buytels as President and Chief Executive Officer and Brian Schmidt as Executive Chairman; the appointment of Headwater nominees to the Tamarack Board and the anticipated management and board composition of Tributary Exploration; revised pro forma production and capital investment guidance; the preliminary pro forma long-term plan of the combined company, including anticipated annual capital investment of $600 – $650 million, annual production growth of 10% – 12%, production of over 110 Mboe/d by 2030, corporate decline rates, sustaining reinvestment ratios, discretionary free funds flow yields and cumulative total shareholder returns through 2030, and the refinement of such plan in connection with the 2027 budget; expected production growth rates of the combined company; the timing and amount of anticipated capital investments; percentage of pro forma production that is pipe-connected; egress on the Trans Mountain and Prairie Connector pipelines; realizing benefits of enhanced egress out of the WCSB; and executing a disciplined capital management strategy and payment of declared dividends. Statements relating to "reserves", "recovery", "EUR", "contingent resources", "prospective resources" and "OOIP" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Statements regarding expected technical revisions to reserves are based on management's assessment of production performance relative to the forecasts underlying Tamarack's year-end 2025 reserves evaluation and are not based on an evaluation or review by Tamarack's independent qualified reserves evaluator; actual reserves revisions will be determined in Tamarack's year-end 2026 independent reserves evaluation and may differ materially from management's current expectations. Future dividend payments and share buybacks, if any, and the level thereof, are uncertain, as the return of capital framework of Tamarack and the combined company and the funds available for such activities from time to time are dependent upon, among other things, free funds flow, financial requirements for the Company's and the combined company's operations and the execution of its strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's and the combined company's control. Further, the ability of Tamarack and the combined company to pay dividends and buyback shares will be subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility. The amount, timing and frequency of any dividends or share repurchases will be at the discretion of the board of directors of Tamarack or the combined company, as applicable, and there can be no assurance that Tamarack or the combined company will pay dividends or repurchase shares at the levels or on the timelines currently anticipated, or at all. The forward-looking statements contained in this presentation are based on certain key expectations and assumptions made by Tamarack, including those relating to: the business plan of Tamarack and the combined company; execution of Tamarack's 2026 budget and guidance; the timing and success of future drilling, conversion, development and completion activities; the timing, amount and performance of additional Clearwater capital investments and secondary waterflood recovery initiatives; the continued performance of Tamarack's waterflood operations consistent with results to date; the accuracy of the internally prepared type curves on which Tamarack's corporate decline rate and recovery estimates are based; the accuracy of the reserves and resources evaluations prepared by McDaniel; the availability of cash on hand, available credit and future anticipated adjusted funds flow to fund planned capital development programs and any future acquisitions, dividends or share buybacks; the geological characteristics of the Company's and the combined company's properties; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's and the combined company's products; the realization of anticipated benefits of the Company's and the combined company's infrastructure, waterflood development program and recent acquisitions and divestitures; the availability and performance of drilling rigs, facilities, pipelines and other oilfield services; the timing of past operations and activities in the planned areas of focus; the performance of new and existing wells; the application of existing drilling and fracturing techniques; the Company's and the combined company's ability to secure sufficient amounts of water; prevailing weather and break-up conditions; royalty regimes and exchange rates; the amount and timing of transaction, integration and other costs; the anticipated tax treatment of the Transaction and the transfer of the Tributary Exploration Assets; the realization of anticipated synergies in the amounts and within the timeframes currently anticipated; the impact of inflation on costs; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or grow applicable banking facilities; the accuracy of Tamarack's geological interpretation of drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; the accuracy and completeness of Headwater's public disclosure and of the information provided by Headwater to Tamarack, on which the information in this presentation relating to Headwater and the pro forma information relating to the combined company is based; and the Company's and the combined company's ability to execute its plans and strategies. Forward-looking statements relating to the Transaction and the formation, financing and proposed public listing of Tributary Exploration are based on the key assumptions of Tamarack regarding: completion of the Transaction on the terms and within the timeframe currently anticipated; the satisfaction of closing conditions; the timing and receipt of required regulatory, court, stock exchange and shareholder approvals; the terms of the arrangement agreement; completion of the transfer of the Tributary Exploration Assets to Tributary Exploration; the accuracy of the pro forma capitalization and ownership information contained in this presentation; the completion of the Tributary Exploration Private Placement on the anticipated terms and for the anticipated gross proceeds; the ability of Tributary Exploration to fulfill the listing requirements of a stock exchange; the expected performance and sufficiency of the Tributary Exploration Assets to support Tributary Exploration's business strategy; the ability of Tributary Exploration to execute its business plan and complete strategic land sales and acquisitions; the compliance by directors and officers of Headwater with the terms of the lock-up agreements; and the compliance by directors and officers of Tamarack and Headwater with the terms of the voting support agreements.
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23 Disclaimers: Tamarack Valley Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: the risk that the Transaction is not completed on the anticipated terms or within the anticipated timing, or at all, including as a result of the failure to obtain the required approvals of the shareholders of Tamarack and Headwater at the special meetings scheduled for November 18, 2026, the final order of the Court of King's Bench of Alberta or the required regulatory and stock exchange approvals, and the risk that, if the Transaction is not completed, the pro forma and combined company information in this presentation will not be reflective of Tamarack's results of operations, financial position or prospects; the risk that the Transaction does not result in the anticipated benefits; the risk that the businesses, operations and personnel of Tamarack and Headwater are not successfully integrated; the risk that the Tributary Exploration Private Placement is not completed on the anticipated terms or at all; the risk that the gross proceeds of the Tributary Exploration Private Placement or the proceeds from the exercise of the Arrangement Warrants are less than anticipated; the risk that Tributary Exploration will not have the capitalization or working capital currently anticipated; the risk that Tributary Exploration does not achieve a public listing or satisfy the listing requirements of a stock exchange; the risk that expected synergies of over $50 million per year are not realized or are delayed; the risk that the lock-up agreements may not be enforceable or that the expiry of lock-up restrictions results in selling pressure on Tamarack's common shares; the risk that the funds that Tamarack or the combined company ultimately returns 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 Tamarack's 2026 guidance is not achieved; the risk that income taxes, general and administrative expenses or interest expenses differ materially from the Company's expectations; the risk that waterflood performance does not continue as anticipated, that actual recoveries are lower than estimated ultimate recoveries or that corporate decline rates and sustaining capital requirements are higher than anticipated; the risk that future technical revisions to Tamarack's reserves are lower than anticipated or are negative; the risk that Trans Mountain or Prairie Connector service does not commence on the timing anticipated or at all, including as a result of delays in the drag reducing agent expansion or the failure of the Prairie Connector pipeline to receive regulatory approval or to be constructed; risks with respect to unplanned third party pipeline outages and risks relating to inclement and severe weather events and natural disasters, such as fire, drought and flooding, including in respect of safety, asset integrity and shutting-in production; the risk that future dividend payments are reduced, suspended or cancelled; incorrect assessments of the value of benefits to be obtained from exploration and development programs; the risk that Tamarack or the combined company may not achieve anticipated water injection rates, anticipated Clearwater oil production or meet the capital investment guidance; the risk that cash on hand, available credit and anticipated adjusted funds flow will not be sufficient to fund the Company's or the combined company's planned capital programs and any future acquisitions, dividends and share buybacks; risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); the risk that (i) the U.S. and Canadian governments maintain tariffs, increase the rate or scope of tariffs, or impose new tariffs on the import of goods from one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry, Tamarack and the combined company; the risks related to the renegotiation of the United States-Mexico-Canada Agreement, resulting in changes to trade, tariff or market access terms that may adversely affect Tamarack, the combined company or Tributary Exploration; commodity prices, including the impact of the actions of OPEC and OPEC+ members; risks relating to reliance on third parties, the uncertainty of estimates and projections relating to production, cash generation, costs and expenses, including increased operating and capital costs due to inflationary pressures; health, safety, litigation and environmental risks; access to capital; pandemics; and the risk that the separation of the Tributary Exploration Assets from the combined company may be more complex or costly than anticipated. In addition, ongoing military actions in Iran and elsewhere in the Middle East and between Russia and Ukraine have the potential to threaten the supply of oil and gas from those regions. The long-term impacts of the actions between these nations remain uncertain. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to respond to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to Tamarack's annual information form for the year ended December 31, 2025, Tamarack's management's discussion and analysis for the three and nine months ended September 30, 2026 and the joint management information circular of Tamarack and Headwater dated October 13, 2026 (the "Circular") for additional risk factors relating to Tamarack and the Transaction, which can be accessed either on Tamarack's website at www.tamarackvalley.ca or under Tamarack's profile on www.sedarplus.ca. Tamarack does not assume any responsibility for the adequacy or accuracy of such information or of forward-looking information relating to Headwater contained in this presentation. Pro forma and combined company information in this presentation is preliminary, has been prepared by Tamarack for illustrative purposes only and, unless otherwise indicated, represents the arithmetic sum of Tamarack's and Headwater's respective standalone information without adjustment. Such information does not purport to represent what the combined company's actual results of operations or financial position would have been had the Transaction been completed on the dates indicated, or to project the combined company's results of operations or financial position for any future period. References to "run-rate" production of the combined company refer to the current combined production of Tamarack and Headwater and are not a forecast of annual average production. The forward-looking statements contained in this presentation are made as of the date hereof and Tamarack does not undertake any obligation to update publicly or to revise any of the included statements, except as required by law. The forward-looking statements contained herein are qualified by this cautionary statement. FOFI Disclosure: This presentation contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Tamarack's 2026 guidance, including the 2026 capital budget of $450 – $470 million, annual average production of 65,500 – 67,500 boe/d, oil and NGL weighting of 88% – 90%, royalty rate, wellhead oil price differential, net operating expense, transportation expense, general and administrative expense, interest expense and income tax expense guidance and the pricing assumptions on which such guidance is based; expected Clearwater production growth; expected exit 2026 water injection rates; expected finding and development costs; the preliminary pro forma long-term plan of the combined company, including annual capital investment of $600 – $650 million, annual production growth of 10% – 12%, production of over 110 Mboe/d by 2030, corporate decline rates, sustaining and capital reinvestment ratios, discretionary free funds flow yields and cumulative total shareholder returns through 2030; free funds flow per share accretion, production forecasts, corporate decline rates, free funds flow breakeven costs, net cash, available funding, the expected capitalization and working capital of Tributary Exploration, the anticipated gross proceeds of the Tributary Exploration Private Placement and the proceeds from the exercise of the Arrangement Warrants, dividends, share buybacks, debt reduction, synergies, balance sheet strength, the revised 2026 capital budget and guidance, and components thereof, including pro forma the completion of the Transaction, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this presentation was approved by management of Tamarack as of the date of this presentation and was provided for the purpose of providing further information about Tamarack's, the combined company's and Tributary Exploration's anticipated future business operations. Tamarack and its management believe that FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represents, to the best of management's knowledge and opinion, Tamarack's, the combined company's and Tributary Exploration's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. Tamarack disclaims any intention or obligation to update or revise any FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. Changes in commodity prices, differences in the timing and allocation of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in Tamarack's and the combined company's guidance. Actual results may differ materially from these estimates.
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24 Disclaimers: Tamarack Valley Reserves Disclosure: All reserve references in this presentation are "Company Gross Reserves". Company Gross Reserves are defined as the applicable company's working interest share of reserves prior to royalty deductions. All reserves values, future net revenue and ancillary information contained in this presentation are derived from evaluations by McDaniel & Associates Consultants Ltd. ("McDaniel") prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGEH") and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") unless otherwise noted. Headwater's reserves and associated net present value are derived from an independent reserves assessment prepared by McDaniel dated January 15, 2026, evaluating the oil and gas properties of Headwater as at December 31, 2025 (the "Headwater Reserves Report"). Tamarack's reserves and associated net present value are derived from an independent reserves assessment prepared by McDaniel dated January 21, 2026, evaluating the oil and gas properties of Tamarack as at December 31, 2025 (the "Tamarack Reserves Report"). Both the Headwater Reserves Report and the Tamarack Reserves Report utilize forecast prices based on the average of forecast prices of McDaniel, Sproule, ERCE and GLJ Ltd. as at January 1, 2026. Reserves information in this presentation for periods prior to December 31, 2025, including historical technical revisions, reserves growth, finding and development costs and recycle ratios, is derived from the independent reserves evaluations of Tamarack's properties prepared by McDaniel as at the applicable year-end, as disclosed in Tamarack's annual information form for the applicable year. Technical revisions, finding and development costs and recycle ratios of Tamarack's peers are derived from such peers' public disclosure; see "Third Party Information". References to "P+PDP" reserves are to proved developed producing reserves plus the probable developed producing reserves associated therewith, and references to "PDP" reserves are to proved developed producing reserves. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by McDaniel in evaluating Tamarack's, Headwater's or the Tributary Exploration Assets' reserves, as applicable, will be attained and variances could be material. Other than with respect to Headwater's McCully assets, which are to be transferred to Tributary Exploration, all reserves assigned in the Headwater Reserves Report and the Tamarack Reserves Report are located in the Province of Alberta. For more information relating to the Headwater Reserves Report and the Tamarack Reserves Report, see the annual information forms of Headwater and Tamarack for the year ended December 31, 2025, which are available on SEDAR+ at www.sedarplus.ca. All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges and general and administrative expenses and after the deductions of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenues presented in this presentation represent the fair market value of the reserves. The recovery and reserve estimates of 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. There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas liquids and natural gas reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. Resource Disclosure: This presentation contains information relating to estimates of heavy oil contingent and prospective resources of Tamarack by McDaniel, a qualified independent reserves evaluator, with an effective date of December 31, 2025, in accordance with the definitions, standards and procedures contained in NI 51-101 and COGEH. The contingent and prospective resources estimates of Tamarack's Clearwater heavy oil contingent resources provided herein are estimates only and there is no guarantee that the estimated prospective and contingent resources will be recovered. Actual resources may be greater than or less than the estimates provided herein and the differences may be material. Tamarack's Statement of Contingent and Prospective Resources dated February 24, 2026, which has been filed on the Company's SEDAR+ profile at www.sedarplus.ca, includes further disclosure of Tamarack's contingent and prospective resources, including the risks and uncertainties related thereto. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. In this presentation, "best estimate" classification is used which is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources identified as best estimate have a 50 percent probability that the actual quantities recovered will equal or exceed the estimate. Drilling Locations Disclosure: This presentation may disclose Clearwater drilling locations in two categories: (i) booked locations; and (ii) unbooked locations. Booked locations are proved and probable locations derived from either the Headwater Reserves Report or the Tamarack Reserves Report, which were prepared in accordance with NI 51-101 and the COGEH. Unbooked locations do not have attributed reserves. Tamarack's unbooked Clearwater locations have attributed contingent or prospective resources, based on the resource report prepared by McDaniel, effective as of December 31, 2025. Headwater's unbooked Clearwater locations do not have attributed resources. References in this presentation to the pro forma combined company's identified drilling locations (including the greater than 3,000 identified drilling locations across the core development areas) represent the aggregate of Tamarack's and Headwater's respective drilling location inventories, on a pro forma basis giving effect to the Transaction. Of Tamarack's Clearwater inventory of > 2,000 (net) primary drilling locations, 520 (net) are proved or probable locations, and the remainder are unbooked locations. Of Headwater's Clearwater inventory of >1,000 (net) primary drilling locations, 273 (net) are proved or probable locations, and the remainder are unbooked locations. Unbooked locations have been identified by management as an estimation of the combined company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Tamarack or the combined company will drill all unbooked 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 Tamarack or the combined company actually drills 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, the majority of 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.
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25 Disclaimers: Tamarack Valley Disclosure of Oil and Gas Information: Unless otherwise indicated, the disclosures in this section apply to the oil and gas properties and activities of Tamarack and Headwater and, where expressly indicated, the combined company on a pro forma basis after giving effect to the Transaction. Disclosure relating to the Tributary Exploration Assets is based on the respective interests of Tamarack and Headwater in the Tributary Exploration Assets prior to completion of the Transaction and the proposed transfer of the Tributary Exploration Assets to Tributary Exploration. Unless otherwise indicated, references to the combined company exclude the Tributary Exploration Assets. For the purpose of calculating unit costs, natural gas volumes have been converted to a boe using a conversion ratio of six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent an equivalency at the wellhead. This conversion conforms with NI 51-101 but may be misleading, particularly if used in isolation. References in this presentation to "crude oil" or "oil" refer to light, medium and heavy crude oil product types as defined by NI 51-101. References to "natural gas liquids" or "NGL" throughout this presentation comprise pentane, butane, propane, and ethane, being all natural gas liquids as defined by NI 51-101. References to "natural gas" throughout this presentation refer to conventional natural gas as defined by NI 51-101. Corporate Decline Rate: "Corporate decline rate" represents the percentage decline of Tamarack's production base, excluding production from new wells drilled in the year, and, where the pro forma combined company's corporate decline rate is referenced, represents the percentage decline of the combined production base of Tamarack and Headwater on a pro forma basis giving effect to the Transaction. Tamarack's and, on a pro forma basis, the combined company's corporate decline rate disclosed in this presentation is based on primary and waterflood type curves that are internally estimated by Tamarack's and Headwater's respective management teams and represent estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The type curves represent what management believes an average well will achieve, based on methodology that is analogous to wells with similar geological features. Individual well results may be higher or lower than the type curve but management expects that, across a larger number of wells, results will come out to approximately the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. Such type curves are useful in understanding management's assumptions of well performance when making development drilling investment decisions in such areas and assessing the success of the performance of development wells. However, internally prepared type curves do not reflect those used by Tamarack's and Headwater's respective independent qualified reserves evaluators in estimating their reserves volumes and no reserves have been assigned to such internal type curves. There is no certainty that Tamarack or the combined company will ultimately recover the volumes indicated by the internal type curves from the wells it drills. Actual results may vary materially from both the primary and waterflood incremental type curve estimates. The cautionary statements in the Oil and Gas Metrics section below apply to corporate decline rate. OOIP Disclosure: The term "original oil in place" or OOIP is that quantity of petroleum that is estimated to originally exist in naturally occurring accumulations. It includes that quantity of petroleum 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. The same uncertainties regarding discovery and commercial viability described in the Resource Disclosure section above apply to OOIP. A significant portion of the estimated volumes of OOIP will never be recovered. OOIP disclosed herein in respect of Tamarack's and the combined company's Clearwater assets by area and in aggregate was internally estimated by the Company's management and has not been evaluated or audited by an independent qualified reserves evaluator. There is no certainty that management's OOIP estimates were prepared in accordance with the COGEH. The estimates may not be comparable to similar measures presented by other companies and therefore should not be used to make such comparisons. Specified Financial Measures: This presentation includes various specified financial measures, including non-IFRS financial measures, non-IFRS financial ratios, capital management measures and supplemental financial measures as further described herein. These measures do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and, therefore, may not be comparable with the calculation of similar measures by other companies. These measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. Unless otherwise indicated, the specified financial measures described below are measures used by Tamarack; Headwater may calculate similar measures differently, and readers should refer to Headwater's public disclosure record for a description of any non-IFRS or other specified financial measures used by Headwater. "Adjusted funds flow" (capital management measure) is defined as cash provided by operating activities excluding asset retirement obligation expenditures, transaction costs and changes in non-cash working capital. Asset retirement obligation expenditures and transactions costs from business combinations both result from Tamarack's capital budgeting and strategic planning processes, which first considers available adjusted funds flow. Asset retirement obligation expenditures vary from period to period depending on capital programs, government regulations and the maturity of Tamarack's operating areas. By also excluding changes in non-cash working capital from cash provided by operating activities, the adjusted funds flow measure provides a meaningful metric for Tamarack and others by establishing a clear link between Tamarack's cash flows, income statement and operating netbacks by isolating the impact of changes in the timing between accrual and cash settlement dates, which can often be within management's control. Tamarack uses adjusted funds flow to assess Tamarack's financial performance and cash generated from operating activities. "Free funds flow" (capital management measure) is defined as adjusted funds flow less investments in oil and natural gas assets (excluding acquisitions and dispositions) and the settlement of asset retirement obligations. Management utilizes free funds flow to assess how much cash was generated in excess of Tamarack's capital investment and asset retirement programs within the same period, which can be utilized to reduce debt, fund acquisitions or return capital. Adjusted funds flow and free funds flow are also expressed on a per share basis by dividing the measure by the basic or diluted weighted average number of common shares outstanding, as indicated. "Net operating expenses" (non-IFRS financial measure and, on a per boe basis, non-IFRS financial ratio) is calculated as operating expenses less processing income. Tamarack generates processing income from third parties that utilize excess capacity at Tamarack's facilities. Net operating expenses allow Tamarack and others to assess the profitability of field operating results by including the associated income generated from plant operations. "Net (cash) debt" (capital management measure) is calculated as the sum of Tamarack's debt, government loans and other, cash, accounts receivable, prepaid expenses and deposits, cross-currency swap liability (asset), assets held for sale (net), accounts payable and accrued liabilities. Tamarack and others utilize net (cash) debt to assess liquidity and balance sheet strength by aggregating the select financial assets and financial liabilities on Tamarack's balance sheet. "Available funding" (capital management measure) is calculated as the sum of undrawn credit capacity under Tamarack's credit facility and cash, accounts receivable, prepaid expenses and deposits, cross-currency swap liability (asset), assets held for sale (net), accounts payable and accrued liabilities. Tamarack and others utilize available funding to assess the amount of funds that could be available to Tamarack in the near term to fund capital management initiatives.
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26 Disclaimers: Tamarack Valley "Sustaining capital" (supplementary financial measure) represents management's estimate of annual capital investments required to maintain corporate production at prior period levels. This measure allows management and others to assess the approximate composition of Tamarack's annual capital investment programs and its corporate financial sustainability. Sustaining capital is also utilized to calculate Tamarack's free funds flow breakeven cost. "Free funds flow breakeven cost" (capital management measure) reflects the average minimum WTI price (US per bbl) received by Tamarack where adjusted funds flow net of the base dividend and sustaining capital requirements is approximately equivalent to zero, with sustained current production levels and all other variables held constant. Management believes that free funds flow breakeven provides a useful measure to establish corporate sustainability. The pro forma free funds flow breakeven cost of US$37 per bbl in this presentation was based on the following assumptions: production of >80,000 boe per day, royalty rate of 13%, operating and transportation expenses of $11.22 per boe, general and administrative expenses of $1.11 per boe, sustaining capital requirements of approximately $240 million, WCS basis of (US$12.00 per bbl), AECO price of $2.11 per Mcf, a foreign exchange rate of 1.35 (USD:CAD) and a quarterly dividend of $0.06 per share. "Total return to shareholders" provides an estimate of the total return generated for shareholders on a percentage basis by aggregating certain select metrics consisting of production growth, dividends, share buybacks and net debt reduction. The return from production growth is calculated as the year-over-year % change in production, dividend growth is based on the yield during year relative to Tamarack's average market capitalization, share buybacks is calculated as the number of Tamarack shares purchased in the year divided by Tamarack's opening common share count and net debt reduction is based on the year-over-year net debt decline relative to Tamarack's average market capitalization. Please refer to Tamarack's management's discussion and analysis for the three and nine months ended September 30, 2026 for additional information relating to specified financial measures including non-IFRS financial measures, non-IFRS financial ratios and capital management measures, including reconciliations of such measures to the most directly comparable measures specified under IFRS, which information is incorporated by reference into this presentation. The management's discussion and analysis can be accessed either on Tamarack's website at www.tamarackvalley.ca or under Tamarack's profile on www.sedarplus.ca.
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27 Disclaimers: Tamarack Valley Oil and Gas Metrics: This presentation contains metrics commonly used in the oil and natural gas industry, such as "corporate decline rate", "NPV-10", "EUR", "IRR", "FDC", "Finding and development costs" or "F&D costs", "finding, development and acquisition costs" or "FD&A costs", "Recycle ratio", "OOIP", "IP30", "IP90" and "CAGR". These terms have been calculated by management and do not have a standardized meaning under NI 51-101 or otherwise. They may not be comparable to similar measures presented by other companies and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Tamarack's and the combined company's 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. F&D costs are calculated by dividing the sum of exploration and development capital expenditures for the period and the change in estimated future development capital for the applicable reserves category by the reserves additions (including revisions) for that category during the period; FD&A costs are calculated on the same basis but also include the cost of, and reserves added by, acquisitions net of dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. "Recycle ratio" is calculated as operating netback per boe divided by F&D costs (or, where F&D costs are not disclosed by a peer, FD&A costs) per boe. The F&D cost of less than $1.00 per bbl for injector conversions presented under "Prolific Waterflood Performance" is calculated using management's estimates of the incremental oil recovery attributable to secondary recovery for all wells under waterflood at year-end 2025 and an assumed capital cost of $0.4 million per injector conversion, and is not based on reserves additions evaluated by Tamarack's independent qualified reserves evaluator. "EUR" or estimated ultimate recovery is management's estimate of the total volume expected to be recovered from a well or pool over its life, based on internal type curves; see "Corporate Decline Rate" above regarding internal type curves. Third Party Information: Certain information contained in this presentation has been obtained from published sources prepared by independent industry analysts and third-party sources (including industry publications, surveys and forecasts). While such information is believed to be reliable for the purpose used herein, none of Tamarack, Headwater or their respective directors, officers, owners, managers, partners, consultants, shareholders, employees, affiliates or representatives assumes any responsibility for the accuracy of such information. Some of the sources cited in this presentation have not consented to the inclusion of any data from their reports, nor has Tamarack sought their consent. The accuracy and completeness of the market, industry and economic data used throughout this presentation are not guaranteed and neither Tamarack nor Headwater makes any representation as to the accuracy of such information. No Offer or Solicitation; Additional Information: This presentation does not constitute an offer to sell or the solicitation of an offer to buy any securities, or a solicitation of a proxy, in any jurisdiction. This presentation is not a substitute for the Circular. Shareholders of Tamarack and Headwater are urged to read the Circular in its entirety, including the risk factors described therein, before making any decision in respect of the Transaction, as it contains important information. The Circular is available under Tamarack's and Headwater's respective profiles on SEDAR+ at www.sedarplus.ca. This presentation is not an offer of the securities for sale in the United States. The securities have not been registered under the U.S. Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an exemption from registration. This presentation shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of the securities in any state in which such offer, solicitation or sale would be unlawful. Abbreviations AECO the natural gas storage facility located at Suffield, Alberta, connected to TransCanada’s Alberta System bbls barrels bbls/d barrels per day boe/d barrels of oil equivalent per day bopd barrels of oil per day DAPPS Debt adjusted production per share EOR Enhanced Oil Recovery ERH extended reach horizontal EUR estimated ultimate recovery FFFPS Free funds flow per share FX foreign exchange GJ gigajoule IFRS International Financial Reporting Standards as issued by the International Accounting Standards Board IP30 average peak production rate for the 30 days after the well is brought onstream IP90 average peak production rate for the 90 days after the well is brought onstream KPI key performance indicator MMcf/d million cubic feet per day Mboe thousand barrels of oil equivalent MMboe million barrels of oil equivalent NAV net asset value OOIP Original Oil In Place P3 proved + probable + possible reserves ROR rate of return ROY remainder of the year TLL total lateral length TTM trailing twelve months TPP total proved plus probable reserves WTI West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade
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28 Slide Notes: Tributary Exploration Slide 20: 1. Total equity issued reflects equity issued by each company under the management team's leadership, from the team's initial financing to the date of sale, and excludes shares outstanding before the team's involvement. Total equity issued includes public and private equity financings, warrant exercises and shares issued as consideration for acquisitions; excludes shares issued on the exercise of options and secondary offerings by shareholders. Wild Stream total equity issued includes $305 million of equity raised plus $75.7 million of shares issued for acquisitions at the applicable deal-date share prices. Raging River total equity issued includes $424 million of equity raised and $163.9 million of shares issued for acquisitions at the applicable deal-date share prices. Headwater includes the $50.0 million March 2020 financing and $93.5 million attributed to the 50.0 million common shares and 15.0 million common share purchase warrants issued to Cenovus Energy Inc. in December 2020 as consideration for the Marten Hills assets, with the common shares valued at $1.27 per share (Headwater's closing price on November 6, 2020, the last trading day before announcement) and the warrants at their $2.00 exercise price. The capitalization immediately prior to Headwater recapitalization was $82.8 million (90 million common shares at $0.92/common share). Charts show equity raises/financings only. 2. Represents total consideration to Wild Stream Exploration Inc. ("Wild Stream") shareholders upon announcement of the business combination between Wild Stream and Crescent Point Energy Corp. ("Crescent Point") on January 25, 2012. For each Wild Stream share, Wild Stream shareholders received 0.17 of a Crescent Point share with a value of $7.94 (based on the $46.70 closing price of Crescent Point shares on January 23, 2012), 1.0 Raging River Exploration Inc. ("Raging River") share with a value of $1.61 per share and 0.2 of a Raging River common share purchase warrant with a deemed value of $0.05, for total consideration of $9.60 per Wild Stream share, multiplied by approximately 74.9 million Wild Stream shares outstanding on a fully diluted basis (plus assumed debt of $43.5 million and transaction costs). 3. Represents total consideration to Raging River shareholders upon announcement of business combination between Raging River and Baytex Energy Corp. (“Baytex”). Represents a Baytex share market price of $5.10 per share on June 15, 2018 (being the date of announcement of the transaction) multiplied by a 1.36x exchange ratio multiplied by 231 million outstanding Raging River shares. 4. Represents total consideration to Headwater Exploration Inc. ("Headwater") shareholders upon announcement of the business combination (the "Transaction" or the "Arrangement") between Headwater and Tamarack Valley Energy Ltd. ("Tamarack Valley"). For each Headwater share, Headwater shareholders will receive 1.0 Tamarack Valley share with a market price of $13.36 per share, 0.33 of a Tributary Exploration share (valued at $0.14 based on a net asset value per share of $0.42) and 0.2 of a Tributary Exploration arrangement warrant (no value has been ascribed to the arrangement warrants), for total consideration of $13.50 per Headwater share, multiplied by 237.8 million outstanding Headwater shares. 5. Calculated as 2.1x ($9.60 exit value per note 2 divided by the $4.50 Wild Stream first public financing price in November 2009) multiplied by 4.3x ($6.94 exit value per note 3 divided by the $1.61 Raging River initial financing price) multiplied by 16.5x ($13.36 Tamarack Valley share value plus $0.14 for 0.33 of a Tributary Exploration share, being the $13.50 exit value per note 4, plus $1.69 of cumulative Headwater dividends declared per share) divided by the $0.92 Headwater initial financing price), or approximately $152. Assumes all proceeds from each transaction were reinvested at the next company's initial financing price; dividends are treated as cash received and not reinvested. No value has been ascribed to the Tributary Exploration arrangement warrants. 6. $50 million of cash assumes all arrangement warrants are exercised in full and that Tributary Exploration raises $30 million from its non-brokered private placement (before the exercise of private placement warrants) and is before any share issue costs and other related fees. 7. $88.3 million of this value represents the net present value of total proved plus probable (“TPP”) reserves discounted at 10% after-tax attributed to the Tributary Exploration assets as evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) prepared on September 4, 2026, effective September 1, 2026 (the “Tributary Exploration Reserves Report”). Based on the Tributary Exploration Reserves Report, the net present value of the TPP reserves discounted at 10% before tax is $100.6 million. The evaluation of Tributary Exploration’s properties was prepared in accordance with the most recent publication of the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The Tributary Exploration Reserves Report utilizes forecast prices based on the average of McDaniel, Sproule, ERCE and GLJ Ltd. as at July 1, 2026. $12.4 million of this value represents undeveloped land value attributed to the Tributary Exploration assets including the Mannville-stack exploratory mineral rights in Alberta, prospective thermal heavy oil opportunities at Handel, Saskatchewan as internally estimated by management of Headwater.
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29 Advisories: Tributary Exploration Certain Oil & Gas Advisories Reserves and Future Net Revenue Disclosures All reserves values, future net revenue and ancillary information contained in this presentation are derived from an evaluation by McDaniel & Associates Consultants Ltd. (“McDaniel”) prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) unless otherwise noted. The reserves and associated net present values attributed to the Tributary Exploration Assets in this presentation are derived from an independent reserves assessment prepared by McDaniel on September 4, 2026, effective September 1, 2026 (the “Tributary Exploration Reserves Report”). The Tributary Exploration Reserves Report utilizes forecast prices based on the average of the forecast prices of McDaniel, Sproule, ERCE and GLJ Ltd. as at July 1, 2026. All reserve references in this presentation are “Company Gross Reserves”. Company Gross Reserves are defined as the working interest share attributable to the Tributary Exploration Assets of reserves prior to royalty deductions. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by McDaniel in evaluating the Tributary Exploration Assets’ reserves will be attained and variances could be material. Additional information relating to the Tributary Exploration Reserves Report will be available in the joint information circular to be provided to shareholders of Headwater and Tamarack in connection with approval of the Arrangement. Additional information relating to the Tributary Exploration Reserves Report is available in the Circular. All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges and general and administrative expenses and after the deductions of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenue presented in this presentation represent the fair market value of the reserves. The recovery and reserve estimates of 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. There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas liquids and natural gas reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. 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. Proved 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. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., 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 category (proved, probable, possible) to which they are assigned. Certain terms used in this presentation but not defined are defined in NI 51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101 (“CSA Staff Notice 51-324”) and/or the COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be.