Slides
Page 1
Corporate Presentation November 2025
Page 2
Tourmaline Overview The Scale, Resource, and Infrastructure Required to Profitably Grow in the WCSB and Provide Returns to Shareholders Tourmaline Overview • Largest natural gas producer in Canada • 4th largest Canadian gas processing midstream operator • 5.5 Billion Boe 2P Reserves; 24.8 Tcf Gas, 1,356 MMbbls liquids • Lowest capital cost operator in the basin • Lowest net emissions and intensity of Canadian senior producers • 41% emission intensity reduction since ‘13; rated “A” by MSCI • Peer-leading cash flow growth & free cash flow generation • Investment Grade BBB (High) rated by DBRS • Largest insider ownership amongst Sr E&P Peers Tourmaline’s scale in Canada’s premium gas plays, production base and low cost infrastructure, provide investors a suite of advantages with efficiency, profitability, growth, and return on (and of) capital unparalleled by peers (1) See schedule A in corporate presentation appendix; inventory life at 325 wells per year pace of development ( hz locations only), reserves and acreage and wells drilled as of December 31 st 2024. (2) Free Cash Flow and dependent ratios and yields are based on current EP Growth Plan ; all market data as per October 23th, 2025; EV presented net of TPZ equity value. (3) See “Non-GAAP and Other Financial Measures” in Forward Looking Statement Advisories of this presentation. (4) Free Cash Flow is defined as Cash Flow less Capital Expenditures(3), excluding acquisitions and dispositions. Market Capitalization (Oct 23rd) $24.0B Net Debt (3Q25)(3) / net of TPZ Equity Stake (Sept 30th)(2) $2.3B / $1.5B 2026E Cash Flow(3) $4.0B 2026E Free Cash Flow(3)(4) $0.9B Financial Position(2) Enterprise Value $25.5B Investment Proposition(2) 2026 FCF Yield + Organic Prod Growth 10% Dividend Yield (Base / TTM Base + Specials) 3% / 5% Total Return CAGR (1/5/10/15yr) 3% / 37% / 13% / 11% EP Growth Plan Production Growth CAGR (‘26-’31) 4% Montney Gas/Cond (Third Largest Montney Producer) Alberta Deep Basin (Largest Deep Basin Producer) Three massive operated complexes, derisked by ~2,925 wells drilled to date with company constructed infrastructure in place Drilled to Date 2025 Drilling Booked Locations Unbooked Resource 75 yrs of Drilling Inventory(1) Nov 2025 2 5.1 MM Net Acres, 5.5 Billion Boe 2P Reserves(1) Peace River High Current Production Forecasts (boepd) • 4Q25E: 655,000 – 665,000 • 2026E: 690,000 – 710,000 (690,000 EP Plan) YE 2024 2P PV10% ATax Reserve Value Per Share $88/Sh
Page 3
3 Largest North American Natural Gas Producers TOU as per guidance, Peer data as per Bloomberg consensus Oct 2025. OVV Canada assumes OVV corporate less most recent US gas production disclosure.. Tourmaline is the largest natural gas producer in Canada, and the fifth largest gas focused producer in North America Nov 2025 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 TOU CNQ ARX OVV CA Petronas JV WCP CVE EXE EQT XOM CVX CTRA Aethon Ascent COP 1 Scale is a key component in driving down costs, leveraging transport & marketing opportunities, and remaining relevant in the current market environment MMcf/d 2025E Natural Gas Production – Canada & US
Page 4
27% 9% 5%15% 23% 21% 2025E Mix 48 55 64 97 112 119 139 149 168 177 181 188 196 200 0 50 100 150 200 250 18 19 20 21 22 23 24 25E 26E 27E 28E 29E 30E 31E Tourmaline Liquids Growth (Mbpd) 5% CAGR Tourmaline: A Significant Canadian Liquids Producer Nov 2025 Tourmaline is a significant liquids producer in Canada, with continued peer leading growth • Tourmaline is the 4th largest producer of conventional liquids , 3rd largest condensate producer, and the largest producer of NGLs (>50% larger than next closest peer) • Tourmaline is planning strong liquids growth with the first phase of the North and South Montney development in the EP Growth plan, adding 50 Mbpd of predominantly condensate and pentanes rich liquids production 149 0 50 100 150 200 250 300 CNQ WCP ARX TOU OVV SCR BTE TVE Conventional Liquids (Mbpd) Conventional Oil & Condensate NGLs 4th Largest Total Conv. Liquids Producer 3rd Largest Condensate Producer Largest NGL Producer Canadian Peer Producers 4 Peer data sourced to most recent public filings or 2025 guidance where available; OVV converted to before royalty interest at 15%; ARX presented proforma SCR Kakwa Condensate Oil C5 C4 C3 C2 North / South Montney 50 mbpd
Page 5
EP Growth Plan(1) Prod’n BOEPD After-tax Cash Flow $MM(2)(3) After-tax CFPS – Diluted E&P Capital Program(4) $MM Free Cash Flow(5) $MM Base Dividend $MM Ending Surplus (Net Debt)(3) $MM 2026E (Strip) 690,000 $3,970 $10.18 $2,900 $915 ($775) ($2,060) 2027E (Strip) 730,000 $3,920 $10.05 $2,900 $865 ($775) ($1,965) 2028E (Flat) 760,000 $5,125 $13.14 $2,850 $2,115 ($775) ($625) 2029E (Flat) 790,000 $5,325 $13.65 $2,700 $2,460 ($775) $1,060 2030E (Flat) 830,000 $5,620 $14.41 $2,775 $2,680 ($775) $2,970 2031E (Flat) 850,000 $5,790 $14.85 $2,630 $2,995 ($775) $5,190 5 Nov 2025 (1) EP Growth Plan derived by utilizing, among other assumptions, historical Tourmaline production performance and current cost a ssumptions, adjusted annually after 2026. 2027 and beyond provided for illustration only. Budgets and forecast beyond 2026 have not been finalized and are subject to a variety of factors including prior year’s results. See Forward Looking Information. (2) Price assumptions: Oct 23 rd, 2025 Strip Pricing for 2026 and 2027 and a flat price deck for 2028 onwards: Gas price - $4.01/mmbtu 2026 NYMEX US, $3.97/mmbtu 2027 NYMEX US, $4.00/mmbtu 2028 to 2031 NYMEX US, $3.25/mcf 2026 to 2027 AECO, $4.08/mcf 2028 to 2031 AECO, $4.39/mcf 2026 PG&E Citygate US, $4.45/mcf 2027 PG&E Citygate US, $ 5.50/mcf 2028 to 2031 PG&E Citygate US, $10.85/mcf 2026 JKM US, $10.32/mcf 2027 JKM US, $12.00/mcf 2028 to 2031 JKM US. Oil price - $59.99/bbl 2026 WTI US, $60.11/bbl 2027 WTI US, $65.00/bbl 2028 to 2031 WTI US. Foreign Exchange – 0.72 2026 USD/CAD, 0.73 2027 USD/CAD, 0.74 2028 – 2031. (3) See “Non-GAAP and Other Financial Measures” in Forward Looking Statement Advisories. (4) E&P Capital Program is defined as Capital Expenditures (3), excluding acquisitions, dispositions, exploration capital and other corporate expenditures. (5) Free Cash Flow is defined as Cash Flow less Capital Expenditures (3), excluding acquisitions and dispositions. Free Cash Flow is prior to dividend payments made by Tourmaline. - 200,000 400,000 600,000 800,000 1,000,000 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Boe/d Spirit River Deep Basin NEBC
Page 6
650 25 50 - 60 25 50 50 >50 500 550 600 650 700 750 800 850 900 950 Production Outlook (Growth to 850 mboepd) July 2025 Tourmaline EP Project Summary Tourmaline’s NEBC build out will include 2 new facilities and 4 complex expansions, 3 new liquids hubs, providing 200 mboepd of high margin volume growth into the next decade See EP Plan for disclosures. mboepd North Montney Ph1 Completion (2026) Production Base 650 mboepd 305 Montney 320 Deep Basin 25 PRH Groundbirch Ph1 (2027/28) West Doe (2028/29) Groundbirch Ph2 (2029/31) North Montney Ph2 (2027/29) Deep Basin Future Expansion PRH Future Expansion NEBC Future Upside Updated EP Plan Future Upside North Montney: • 75 mboepd (+ Upside) • Aitken Complex Expansion • Highway Liquids Hub • Conroy Complex South Montney: • 125 mboepd (+ Upside) • Sundown Expansion • Groundbirch Ph1&2 • West Doe Complex Expansion EP Expansion Highlights • Aitken Expansion • Birch Compression • Highway Condensate Hub • New GB Plant • Sundown Electrification & Expansion • Wilder Electrification & Expansion • NRM JV Exp • Parkland compressor • Conroy Plant • Conroy Compressor • GB Ph2 Exp • South GB Expansion 2025 Guide + Full Year of Acq Vols 6
Page 7
2024-2031 NEBC Infrastructure Project Overview July 2025 • This is the largest EP growth project in the WCSB over the next 5 years and is timed to the growing Canadian LNG business. • Tourmaline expects to add 1.1 bcf/d of new gas production and over 50,000 bpd of condensate and ngls over the next six years • The two-phase project will systematically develop Tourmaline’s most profitable resource inventory (lowest capital cost, lowest operating cost, most liquid rich, highest margin), resulting in Tourmaline’s operating metrics improving as production from this new development project becomes a larger proportion of the corporate production base. • The build out consists of two new gas processing complexes with C3+ deep cut recoveries, expansion of four existing gas processing complexes, three new hydrocarbon liquids hubs including evaluation of an LPG terminal at Groundbirch, five water recycling facilities, electrification of four processing plants of which two are existing, and several large pipeline corridors connecting our large resource base to the existing and new gas processing complexes. • The infrastructure build-out commenced in 2024 with one of the liquid storage projects, one of the connector pipeline projects, a water facility, the compression expansion at Birch, and one of the electrification projects all expected to be completed by end 2025 on approximately $350 million of aggregate capital spending. • The first material production addition occurs in Q4 2026 with the Aitken C-38-C plant expansion, the next significant production addition is phase one of the Groundbirch 15-25 deep cut planned for 2H 2027. Both projects are permitted and long-lead procurement is underway. • Tourmaline expects production growth of 30%, cash flow growth of over 40% and free cash flow growth of 2.5 times at flat pricing once the project is completed and the EP program trends towards maintenance capital levels ($>3.0 billion FCF per Annum). ‘We’re not just growing the business; we’re improving the business.’ 7 See EP Plan for flat pricing and other disclosures.
Page 8
NEBC Montney Gas/Condensate Complex July 2025 Tourmaline is one of the largest Montney producers in Western Canada with current NEBC production of 320,000 boepd Current Prod. 320,000 boepd Current Reserves 3,279 mmboe (Dec 31, 2024) Montney Drilling In excess of 7,857 horizontal Inventory locations. (Dec 31, 2024) 8 Tourmaline Gas Plant Third Party Gas Plant Tourmaline Land Legend Sales Pipelines Tourmaline Compressor Station Gundy Complex 400 mmcf/d NRM Jedney NRM McMahon AltaGas Townsend NRM Aitken/Hwy Groundbirch Complex 60 mmcf/d Sundown Complex 130 mmcf/d Doe/Sunrise Complex 260 mmcf/d Aitken Complex 330 mmcf/d Septimus/Wilder Complex 185 mmcf/d *Includes West Doe Processing Complex Name Current Capacity (mmcf/d) Planned Capacity (mmcf/d) Aitken 330 450 Gundy 400 400 Septimus/Wilder 185 220 Groundbirch 60 Up to 500 Doe/Sunrise* 260 410 Sundown 130 250 Conroy 0 Up to 250 3rd Party 350 ~350 Total 1.7 Bcfpd ~2.8 Bcfpd
Page 9
Tourmaline Gas Plant Tourmaline Lands Legend • Current Production 320,000 boepd • Current Reserves 1,945 mmboe (as at Dec 31, 2024) • Tourmaline Land Base 3.2 million acres • Drilling Inventory 14,794 hz locations The Company has drilled 1,345 wells to date with a future drilling inventory of 14,794 hz locations The contiguous Tourmaline interconnected Deep Basin Cretaceous gas asset is effectively Alberta’s Largest Gas Field Doe Creek Viking Falher Wilrich Bluesky / Glauconitic Gething Cadomin Cardium Dunvegan Notikewin Nikinassin TCPL TCPL TCPL Hinton Musreau /Kakwa Brazeau Cynthia Willesden Green Badger Pine Creek Rosevear Wild River Cutpick Netook Ricinus Garrington Westerose Crossfield Oldman Ansell Columbia Strachan Bashaw Hanna Alberta Deep Basin Mar 2025 9 AlbertaNE BC
Page 10
Mar 2025 10 Peace River High • 2,428 Horizontal Locations* along Regional Play Fairways • Current Reserves of 272 mmboe (Dec 31, 2024) • Regional pools defined by >400 horizontal wells • 2.5 – 3.4 bcfe 2P reserves per horizontal Charlie Lk/Montney • $3.0 - $4.5M Charlie Lake / Montney horizontal Drill/Complete Cost • Upper Charlie Lake wells are profitable on a full cycle basis at $30/bbl (U.S. WTI) Peace River High Complex Triassic Oil Charlie Lake, Montney and Wapiti Cardium Plays Wapiti Cardium Complex T. 68 T. 67 T. 66 T. 65 R. 9 R. 8 R. 7 R. 6 R. 5. W6MR. 10 Cardium Oil Window Cardium Gas Window T. 75 T. 77 R. 9 R. 7 R. 5R. 11 T. 83 T. 81 T. 79 Earring Bonanza Mirage Mulligan 15-13 Mulligan Oil Battery 12-6 Mulligan Oil Battery 6-3 Spirit R. Oil Battery Montney 3-10 Spirit R. Gas Plant Spirit River * See Schedule A Tourmaline HZ Wells Tourmaline Gas Plant Legend Tourmaline Lands Tourmaline Battery Site Lower Charlie Lake Fairway Upper Charlie Lake Fairway Montney Fairway 0 10 20 30 40 50 60 Cumulative Oil IPP90 (Mbbl) Charlie Lake 2024 / 2025 Pads
Page 11
July 2025 Water Infrastructure • 8 Facilities (13 ponds) of frac water source / recycling with 585,000 m3 capacity >$400MM per year of cash flow is effectively preserved by owning the operated infrastructure and not processing gas through third party/midstream plants. The infrastructure skeleton in all three core operated complexes is now complete This infrastructure is essentially all new and in the ‘growth’ areas of the WCSB Current Tourmaline operated gas processing capacity of 3.3 bcf/day. (>2.9 bcf/day net) Two oil processing batteries with combined processing capacity of 50,000 bpd Oil, condensate and NGL storage capability of 330,000 bbls 16 MW gas fired electrical generating capacity 15,500 km of Tourmaline Operated Pipelines 34 working interest1 gas plants, 19 of which are 100% owned and operated, 4 Topaz interest plants Tourmaline Midstream Assets 11 Peace River High Charlie Lake Oil Alberta Deep Basin Tourmaline Gas Plant Tourmaline Oil Battery Tourmaline Land Legend Sales Pipelines Tourmaline Pipeline Infrastructure stats as of YE 2024 + Strath GB (1) 33 plants with working interest greater than 20% Montney Gas / Condensate
Page 12
12 Nov 2025 North American Natural Gas Reserves Rockies LNG Sumas LNG Canada Canadian reserves represent most recent 2P disclosure (Nat Gas only) US peers represent Proved Reserves (Nat Gas) Canadian Peers: CNQ, ARX, PEY, BIR, AAV, WCP Permian Peers: XOM, CTRA, EOG, CVX, COP, OXY, FANG, DVN, Appalachia Peers: EQT, RRC, AR, CNX Haynesville Peers: EXE, BP, CRK 26 25 8 7 6 5 3 TOU 2P Reserves (Tcf) Canadian Peers 17 5 4 Haynesville Peers 17 10 9 7 6 5 5 4 Proved Reserves (Tcf) Permian Peers Midland Delaware Haynesville Montney Ventura Chicago NIT St. 2 Malin Corpus Christi Sabine Pass Jefferson Island PGE Citygate Iroquois Dawn Deep Basin Emerson Marcellus Utica Companies that own the largest, lowest development cost, transport-integrated natural gas reserves, will increasingly dominate the Energy space in the next 20 – 30 years 25 12 11 8 Appalachia Peers Permian Basin Appalachia Basin Western Canadian Sedimentary Basin TOU owns and operates 3.3 Bcfpd of gas processing infrastructure
Page 13
$- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 0 1,000 2,000 3,000 4,000 5,000 6,000 A.Tax Break-Even Gas Price (C$/GJ AECO, US$65 WTI) Drilled to Date 2025 Drilling Booked Locations Unbooked Resource 75 yrs of Drilling Inventory Multiple Decades of Tier 1 Inventory July 2025 Tourmaline’s deep inventory ownership provides multiple decades of very profitable development, plus no need to pursue large “resource reloads” in A&D market PV10% Breakeven as per internal analysis; liquids realizations as of July 2025 strip 2025/2026+ avg % of EDM40 derated to US$ 65 WTI; Milestones breakeven exhaustion per Enverus Locations Years of Drilling @ 300 wells/yr 5 10 157 12 Milestones: Breakeven Study Locations ~1/4 Total Locations 17 20 13 Average Breakeven (A-Tax @ $65/bbl) • Deep Basin $2.00/Gj • Corporate C$1.60/Gj • Montney C$1.40/Gj
Page 14
Doe Spirit RiverSunrise- Dawson Mulligan/Earring Gundy Conroy Birley Hinton EdsonMarsh Minehead Pine Creek Lovett Brazeau Musreau/ KakwaChinook Ridge Lynx Strachan Crossfield Willesden Green Bashaw Rosevear Westrose British Columbia Alberta July 2025 A Unique, Expanding Exploration Program 2024 Highlights and Significant Planned 2025 Wells Exploration program success has created significant incremental value in existing core complexes, the majority of the discoveries can access Tourmaline infrastructure. 22 new zones discovered, with 140 successful new zone or follow up wells drilled since inception. 2,037 bcfe booked in YE 2024 reserve report, since starting the program. 1,068 incremental locations added to inventory to date. Groundbirch-Sunrise Montney SQ2 • 1-24-80-16W6 (Recent Test) • IP. 180 – 2.53 mmcf/d & 256 bbl/d cond/C5+ EUR - 3.1 bcf & 204 mmbbls cond/C5+ • 128 Incremental locations Legend 3rd Party Gas Plants Tourmaline Oil Battery Tourmaline Pipelines Main Sales Pipelines Gas Discovery Tourmaline Gas Plant Tourmaline Lands 2025 Strachan Multi Objective New zone/New Pool Test • Potential material gas/condensate discovery • 91 Incremental locations Garrington Glauc NPW 2025 • 37 potential locations with multizone upside 2024 Ferrier Glauc Gas/Cond Success • 9-28-38-07-W5M Pad • 09-26-038-07W5 HZ – 7.2 bcf raw, 120 mbbls cond/C5+ • 16-26-038-07W5 HZ – 7.2 bcf raw, 120 mbbls cond/C5+ 2024 Deep Basin New Zone • Vertical Pilot well drilled • 3 Hz wells drilled into zone • 3 well average EUR of 8.6 bcf • Over 40 Potential locations Wilson Creek Belly River 2025 NPW • First pad spud Q1-Q3 2025 • 35 potential locations Mntn 2025 New Zone Test • Tested at 12.5 mmcfpd • Multiple follow-ups planned Groundbirch 14
Page 15
Continuous D&C Performance / Cost Improvements Mar 2025 15 4,000 5,000 6,000 7,000 8,000 9,000 10,000 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Average Lateral Feet per Well Deep Basin NEBC PRH $5.4 $4.3 $4.0 $4.1 $4.1 $3.8 $3.9 $5.1 $6.2 $6.7 $4.2 $2.9 $3.0 $3.1 $2.9 $2.8 $3.3 $4.3 $5.5 $5.3 $3.1 $2.6 $2.5 $2.9 $3.0 $2.4 $2.5 $3.4 $3.9 $4.2 $2.0 $2.5 $3.0 $3.5 $4.0 $4.5 $5.0 $5.5 $6.0 $6.5 $7.0 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 D&C Costs per Well Deep Basin NEBC PRH $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 D&C Cost per Lateral Foot Deep Basin NEBC PRH 49 84 137 107 101 80 106 93 108 112 40 36 80 53 82 101 140 159 124 142 28 26 59 64 35 13 15 25 25 24 0 20 40 60 80 100 120 140 160 180 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Wells Placed on Production Deep Basin NEBC PRH An increasingly NEBC dominated development program ~50% increase in corporate lateral length since 2018 Inflation headwinds were realized in 2022 – 2024 however… … On a normalized per foot basis corporate D&C costs are still under C$775/ft despite… $mm Feet $/Ft 0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Tonnage per Lateral Foot Deep Basin NEBC PRH … Steadily higher tonnage in NEBC T/Ft +62%
Page 16
0 20 40 60 80 100 120 Deep Basin Vintage Curves (Wellhead Recovery Mboe) 0 20 40 60 80 100 120 NEBC Vintage Curves (Wellhead Recovery Mboe) 2025 2020 - 2024 Average Tourmaline Vintage Type Curves Nov 2025 16 TOU Internal Data; includes data as of October 1st 2025; includes only wells with at least 90 days of production history; Green: 2025 IP90, Black: 2020 -2024 Average, Grey: 2020 – 2024 individual vintages Through longer laterals, improved completions, and accessing new prolific resource areas, the NEBC Montney and the Alberta Deep Basin are both posting at or above historical type curve performance in 2025 2025 +26% vs 5-year average 2025 matching 5-year average with increasing liquids mix 90 Days 90 Days
Page 17
$20,900 $15,500 $9,500 $9,500 $11,200 $8,650 $7,300 $8,000 $8,900 $10,700 $11,800 $12,500 $- $2,500 $5,000 $7,500 $10,000 $12,500 $15,000 $17,500 $20,000 $22,500 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025E $/boepd Continuous Capital Efficiency Improvements July 2025 (1) Based on EP Growth Plan Guidance 17 Tourmaline maintains best in class capital efficiencies (1)
Page 18
2025 Natural Gas Transportation and Marketing Overview Nov 2025 • 2026 Exit: 1.25 Bcf/d of gas will flow to US/Other Markets • In 2026: 30,000 MMBtu/d of new TTF exposure in April • In 2027: 62,500 MMBtu/d of JKM exposure in January and 50,000 MMBtu/d of new TTF exposure in April • In 2028: 80,000 MMBtu/d of TTF exposure Dawn/IGTS/GLGT/Emerson/Empress ~243 MMcf/d 16% AECO 11% Kingsgate US West ~527 MMcf/d Station 2 *Average volumes 2% US Midwest/US Gulf Coast ~365 MMcf/d 7% 9% 8% 8% 8% 3% 3% 2% 2% 2%6% 6% 6% 6% 6% 12% 14% 14% 14% 14% 2% 2% 2% 2% 2% 13% 13% 14% 15% 16% 16% 32% 48% 50% 51% 41% 21% 6% 3% 1% 2025 2026 2027 2028 2029 Natural Gas Price Exposure US Gulf/LNG US Midwest Dawn/IGTS/GLGT PG&E/Malin/King Nymex Basis Stn2/Hunt Empress AECO Hedged 18
Page 19
Nov 2025 Tourmaline continues to grow its international pricing exposure Rockies LNG - Partner • A partnership of Western Canadian natural gas producers working together to supply Ksi Lisms LNG • Ksi Lisims has received a British Columbia Environmental Assessment Certificate and a positive Decision Statement from the Government of Canada • SPA’s executed with Shell and Total Tourmaline LNG Overview NeeStaNan Utility Corridor (Hudson Bay LNG) - Supporter • Access to Northern Ports and interprovincial and international trade • Ownership consortium of Indigenous groups • Tourmaline is an initial industry supporter of NeeStaNan and is helping to fund feasibility studies for the project NeeStaNan Utility Corridor Rockies LNG Tourmaline Lands LNG Canada Cheniere Sabine Pass Liquefaction Facility 19 LNG Agreements • Cheniere: 140 MMcfpd with JKM Exposure, 15-year term starting Jan 2023 • Trafigura: 50 MMcfpd TTF Exposure (NIT delivery), from Mar 2024-Dec 2026 • Hartree: 30 MMcfpd TTF Exposure, 1-year term starting Apr 2026 • EDF: 50 MMcfpd TTF Exposure, 19-month term starting Apr 2027 • Trafigura: 62.5 MMcfpd JKM Exposure, 7-year term starting Jan 2027* • Uniper: 80 MMcfpd TTF Exposure, 8-year term starting Nov 2028 • Centrica: 50 MMcfpd TTF Exposure (NIT delivery), 10-year term starting Apr 2028 *Potential extension to 2039 0 100 200 300 400 2023 2024 2025 2026 2027 2028 2029 2030 2031 LNG Exposure (000's MMBtu/d) Cheniere Trafigura Uniper EDF Hartree Centrica
Page 20
The Growing Tourmaline Liquids Business July 2025 20 Canadian Peers, WCP, ARX, OVV US Gas Peers: AR, CNX, EQT, EXE, RRC All figures based on latest available corporate disclosure Tourmaline Margin Improving Activities • MMLP North Montney Liquids Pipeline • Aitken Plant Consolidation • West Doe Plant Acquisition / Ownership • Pembina NEBC Liquids Agreement (Frac & Transport) • South Montney Rail / Frac Site • Gundy NGL Dual Connection North Pine Rail & PPL NEBC Pipe • Access to All Fractionation in Ft Sask (+ Take in Kind Rights) 203 116 97 71 29 US Gas Producers Oil & NGL Production (Mbpd) US Gas Producer Peers 149 237 172 125 TOU Canadian Peer Producers Oil & NGL Production (Mbpd) Canadian Peer Producers Oil/Condy NGL Tourmaline’s diverse and profitable liquids marketing business • Liquids receive diversified pricing: WTI, FSPL, Namao/Peace, CRW, Mt. Belvieu, Conway, Far East Index, and Polypropylene netbacks • NGL volumes are meaningfully exposed to all Canadian west coast waterborne export terminals (RIPET, PRT) • Tourmaline ships liquids to markets on pipelines traversing our core areas – most cost-efficient method of transport CN Rail
Page 21
Liquids & Midstream Investment Mar 2025 21 Internal data; Midstream related costs include Oil and Liquid Transportation, G&P fees and Frac/Load costs Tourmaline has repeatedly driven midstream related costs down through acquisition, investment and expansion, while also driving liquids revenue higher through international marketing and integration North Montney: Aitken Investments • Acquire ALA ownership and expand $295mm • Growth and integration $285mm (2025 – 2027) Margin Improvement • 100% ownership in Aitken processing • Integration with ALA NEBC frac / rail / export • Cost savings through growth and integration • To date ~45% reduction in midstream cost • Targeting additional ~25% reduction $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 At Acquisition 2024 Growth & Integration North Montney: Aitken Midstream Cost ($/boe) Phase 1 (2021) Phase 1 + 2 (2024) Optionality North Montney: Gundy Midstream Cost ($/boe) North Montney: Gundy Investments • Gundy Ph1 $190mm (GP Only) • Gundy Ph2 $140mm (GP Expansion) Margin Improvement • TOU built / op (capital & runtime advantage) • Propane integrated with ALA NEBC rail / export • Butane optionality local / NA • To date ~20% reduction in midstream cost • Targeting additional ~20% reduction At Acquisition 2025 Exit Growth & Integration South Montney: Crew Midstream Cost ($/boe) South Montney: Crew Investments • Increase ownership in existing processing • Fund and own 100% of new midstream Margin Improvement • Near term grow production thru excess capacity with fixed cost structure • Medium term execute Groundbirch Ph1 growth and integration (analogue is Gundy Ph1) • Long term execute Groundbirch Ph2 Target similar or better Midstream cost as Aitken / Gundy analogues
Page 22
July 2025 Growing Corporate Margins Through NEBC Development Tourmaline’s NEBC growth projects improve realizations, while lowering costs driving margin growth; $1/boe in lower operating & transport costs, with $1/bbl liquids mix uplift drives ~$400mm in annual additional margin See EP Plan for disclosures; Opex and Transport outlook are done on a ‘real’ basis with no assumed inflation; liquids mix shift illustrative on a flat price de ck $10.41 ~$9.50 $9.00 $9.50 $10.00 $10.50 1H25 2025E 2026E 2031E Opex & Transport Cost Structure Outlook ($/boe) 149 168 177 181 188 196 200 0 50 100 150 200 250 2025E 2026E 2027E 2028E 2029E 2030E 2031E Liquids Growth and Composition Outlook (mbpd) Condensate Oil NGLs $1/boe Cost Improvement Target • NEBC vs DB/PRH Corp Blend Down • Local Market Transport Blend Down • Liquids Transport Pipe/Rail Build Out • Groundbirch Complex Build Out • Aitken Complex Completion • Conroy Complex Build Out • Acquired Asset Cost Optimization C2 21% C3 23% C4 15% C5 Oil Condensate 27% 2025E Liquids Composition C2 16% C3 24% C4 17% C5 Oil Condensate 33% 2031E Liquids Composition $1/bbl Liquids Mix Improvement with Marketing Upside 22
Page 23
Guidance Nov 2025 23 2026(1) Production – Boe/d 690,000 – 710,000 Cash Flow(i) - $MM $3,970 (at 690,000 boepd) CFPS - Diluted(i) $10.18 (at 690,000 boepd) E&P Capital Program(ii) - $MM $2,900 Capital Expenditures(i) - $MM $3,055 Free Cash Flow(iii) - $MM $915 (at 690,000 boepd) (1) Price Assumptions: Oct 23rd, 2025 Strip Pricing: Gas price - $4.01/mmbtu 2026 NYMEX US, $3.25/mcf 2026 AECO, $4.39/mmbtu 2026 PG&E Citygate US, $10.85/mcf 2026 JKM US; Oil price - $59.99/bbl 2026 WTI US; Foreign Exchange – 0.72 2026 USD/CAD. (i) See “Non-GAAP Measures and Other Financial Measures” in the Forward Looking Statement Advisories section of this presentation. (ii) E&P Capital Program is defined as Capital Expenditures(i), excluding acquisitions, dispositions, exploration capital and other corporate expenditures. (iii) Free Cash Flow is defined as Cash Flow less Capital Expenditures(i), excluding acquisitions and dispositions. Free Cash Flow is prior to dividend payments made by Tourmaline.
Page 24
Tourmaline 2026 After Tax Cash Flow Sensitivity & Allocation For sensitivity capital and basis assumptions and definition of free cash flow please see EP Growth Plan slide; C$ AECO assum ed to match US$ NYMEX at each sensitivity level, all other basis as of Oct 23 Strip Nov 2025 24 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 $5,000 '26 Cash Flow Per NYMEX/AECO Price Maintenance Budget TOU Base Dividend ~5% Production Growth Per Year Available Funds 2026 AT Cash Flow NYMEX/AECO Sensitivity & Allocation Cash Flow at $1.50/Mcf $2.00/Mcf $2.50/Mcf $3.00/Mcf $3.50/Mcf $4.00/Mcf >$4.00/Mcf $1,900mm (C$mm) $775mm $1,000mm (Oct 23rd Strip WTI) 2026 NYMEX Calendar Strip – Recent Trading Range Tourmaline’s low cost structure drives sustainable return on, and of, capital opportunities • TOU’s maintenance budget, and dividend is fully funded at US$2.15/mcf NYMEX & C$2.15/Mcf AECO • TOU will manage growth capital in each annual EP program to achieve free cash flow of ~$1bn or greater • FCF allocated to base & special dividends, defensive buybacks, infrastructure, and exploration Maintenance + Dividend Coverage at $2.15/Mcf Available For: (1) Base Div Incr. (2) Special Div (3) Inf. Investment (4) Exploration (5) Buybacks 2026 Growth Capital 2026 FCF After Base Dividends $2.00/sh, 3% Yield
Page 25
Annual BTax Cash Flow $65 WTI / $4 HHUB/AECO Base CF Liquids Mix & Cost Saving Growth Annual BTax Free Cash Flow $65 WTI / $4 HHUB/AECO Base FCF CF Growth Shift to Maintenance Capex Production Outlook (Growth to 850 mboepd) Current mboepd Nat Gas C3/4/5 Condensate July 2025 Tourmaline Long Term Value Progression Illustrative ‘Flat Deck’ CF & FCF Outlook +1 Bcfpd 50 Mbpd >1/3 Condensate No Ethane Growth $4.6bn BTax CF at 640 Mboepd Infrastructure & BC weighting Cost Improvement ($1/boe) $300mm NGL Mix Shift (+$1/bbl) $100mm +$1.5bn 640 Mboepd $1.6bn BTax FCF 5% EP Growth +$1.9bn Cash Flow Growth +$0.4bn ~$6.5bn/yr Btax CF @ 850 mboepd850 mboepd (3.9 Bcfpd & 205 mbpd) ~$4bn/yr BT FCF @ 850 mboepd >$3.0bn/yr AT FCF Steady State Maintenance Capex $2.5bn +$0.5bn Investments in NEBC will double FCF generation through volume growth, margin expansion, and a migration to maintenance capital to enhance shareholder returns at 850 mboepd • 30% production growth facilitates >40% cash flow growth through margin expansion and efficient BC operations • FCF generation grows by 2.5x as widening cash flow margins combine with maintenance capital at 850 mboepd • Buildout from 640 to 850 mboepd will sequence volume growth into strongly priced demand markets while ensuring ongoing free cash generation continues to fund shareholder returns over and above the base dividend • Tax adjusted, future maintenance FCF implies >12% annual cash returns for shareholders at today's valuation All data illustrative on a $65/4/4 WTI/HHUB/AECO price deck, before tax. Volume Growth 25
Page 26
Tourmaline Free Cash Flow Allocation & Dividend Growth Track Record The majority of Tourmaline’s free cash flow will be returned to shareholders; a growing base dividend and special dividends will be the preferred method of shareholder returns • Base dividend will continue to grow alongside the base EP business with FCF coverage even in $2/mcf gas prices • Special dividend offers an instrument for cash return to shareholders during accommodative commodity prices • Alongside dividends, free cash flow will be allocated towards: (1) maintaining a pristine balance sheet, (2) high return infrastructure investment opportunities, (3) modest exploration, (4) defensive share buybacks • Tourmaline plans to continue to provide a total return of >10% through income and growth through the EP plan Nov 2025 26 $0.46 $0.50 $0.67 $0.90 $1.05 $1.32 $2.00 $0.75 $7.00 $5.50 $2.00 $1.30 $0.51 $1.01 $4.78 $9.56 $6.55 $3.32 $3.30 $2.36 $2.24 $5.47 $6.36 $6.93 $7.74 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 19 20 21 22 23 24 25E 26E 27E 28E 29E 30E 31E Free Cash Flow & Dividends per Share Annual DPS Announced Special Excess FCF/Share Buildout includes >$2/sh of growth capex per year which can be reproportioned to Free Cash Flow pending market circumstances For capital and commodity price assumptions and definition of free cash flow please see EP Growth Plan slide; FCF & Dividends per share as per basic shares. (Strip) ($65/$4) $0.50 $0.75 $0.25 Q3 Base Dividend Special Dividend Total Q3 Dividend 3Q25 Dividends 4% 10% 6% '26 FCF/Sh Yield YoY Production Growth 2026 Total Return 2026 Total Return Flexibility to Reallocate 5% Annualized Yield
Page 27
Tourmaline Long Term Business Plan Growth & Leading Shareholder Returns July 2025 27 Long term outlook per EP plan; 2031+ illustrative Continued Modest Growth Evolving Towards 1-2% Production Growth with Enhanced FCF Harvest Production Growth Large Project Sequencing Consistent Shareholder Returns Additional Optionality and Upside N. Montney Ph1 600 700 800 2026 2028 2030 2032 Groundbirch N. Montney Ph2 0% 5% >10% Tourmaline, 4th Largest Midstreamer in Canada >10% Targeted Returns Evolving with the Business Layers of Value Incremental Capital Opportunities • Topaz Equity • Internal Value Crystallization • Asset Sales • Run Rate D/CF 0.3 – 0.4x ($1.5bn LTD) Midstream Margin Improvements • Liquids Midstream (Rail, Liquids Hubs) • Gas Midstream (BC Processing Infra Growth) Exploration Program • Ongoing New Pool / Zone Exploration • Large Pool Tests in 2026 - 2028 Base Business NEBC Growth Deep Basin Growth Growth Yield Buyback 850 mboepd >$2bn West Doe
Page 28
Market Leading Return on and of Capital Nov 2025 28 ROCE defined as Income before taxes and Finance expense divided by Capital Employed, where Capital Employed is defined as the average of Total Assets less the average of Current Liabilities for the respective year. ROCE (Enterprise Value Adjusted) is calculated by multiplying ROCE by the Capital Employed to Enterprise Value ratio implied in the annum. For the purposes of ROCE, Tourmaline’s Income before taxes and Finance expense has been adjusted to exclude gain on acquisiti on ($250mm in 2021, $122mm in 2022, $82mm in 2023, $279mm in 2024), gain on loss of control of Topaz ($321mm in 2021) and unrealized gain (loss) on financial instruments ( -$93mm 2021, $2,101mm in 2022, -$658mm in 2023, -$299mm in 2024). Magnificent 7 = META, AAPL, AMZN, NFLX, NVDA, TSLA, GOOG; Renewables = ENPH, ALB, ON, QS, VWS, FSLR; O&G Infra = TRP, PPL, PA A, KMI, LNG, ENB; Industrials = CNR, CP, UNP, WCN, CAT, BA, GE, TRA; Materials = FM, NTR, TECK/B, AA, BTU, NUE, FCX, K. E&P = ARX, CNQ, EOG, RRC, OVV, EQT, EXE; All market data as of Sept 30th 2025 as reported by Bloomberg; All Tourmaline data as per the EP plan and company filings Tourmaline’s return on capital employed (“ROCE”) will inflect to >10% with base and special dividends offering a future income yield in the mid to high single digits with upside in stronger commodity price environments 24% 16% 9% 9% 11% 33% 11% 9% 9% 9% 2% 18% 14% 7% 7% 10% 2% 8% 6% 3% 8% 3% 2022 2023 2024 2025E 2026E Magnificent 7 E&P O&G Infra Industrials Materials Renewables ROCE ROCE (Enterprise Value Adjusted) Dividend Yield (DPS / Current Price) 10% 5% 0% 3% 5% 1% 1% Tourmaline The ‘Magnificent 7’ have some of the best ROCE results in the world, but investors buy the businesses at >8x book value Tourmaline offers investors the ability to earn a ‘magnificent’ return at a fair price while also receiving a market leading dividend ‘24 Avg: 0% ROCE x (Capital Employed / EV ) 5% 3-5%
Page 29
APPENDIX
Page 30
Historical EP Performance 0 2 4 6 8 10 12 14 16 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Reserves Per Share* 0 100 200 300 400 500 600 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Production Per Share* Boe / 000 Shares $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Operating Costs / BOE Mar 2025 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Cash Flow Per Share • 2014-2024 Production growth per share CAGR of 12% • 2P BTax NPV 10% Reserve Value of $41 billion • Leading low capital and cash costs allow Tourmaline to grow profitably and pay a meaningful dividend in all parts of the natural gas price cycle * Debt adjusted 30 Boe / Share
Page 31
1,356 0 500 1,000 1,500 2,000 2,500 Peer 1 Peer 8 TOU Peer 9 Peer 2 Peer 6 Peer 7 Peer 12 Peer 13 Peer 3 Peer 10 Peer 4 Peer 11 Peer 5 Independently Recognized Canadian 2P Reserves(1) May 2025 (1) Canadian Protocol, most recent disclosure. Peers include Advantage, ARC, Birchcliff, CNRL, Cenovus, Kelt, NuVista, Paramount, Peyto, Strathcona, Suncor, Tamarack, Whitecap / Veren (Proforma) 31 25 0 5 10 15 20 25 30 Peer 1 TOU Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Natural Gas 2P Reserves Conventional Liquid 2P Reserves Tcf MMbbl
Page 32
357 41 90 94 97 82 77 70 94 35 17 8 10 5 Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer BC and Alberta Montney Peers Current Announced Expansions (2025+) 255 280 330 >450 0 50 100 150 200 250 300 350 400 450 500 2023 Exit 2024 Exit '25 - '27 2027+ Tourmaline Montney Significant Montney Growth Potential Peer data as per most recent disclosure; Accumap, Peters & Co. research. Expansions include publicly announced growth, and/or budgeted volume growth. Peers include AAV, ARX , BIR, CNQ, COP, Mitsubishi (Diamond Gas), MUR, NVA, OVV, Petronas JV, Shell Canada July 2025 Mboepd North Montney Ph2 South Montney Ph1/2 Tourmaline growth projections include development of existing assets, all are fully delineated and are economic / full cycle profitable on current strip pricing. This analysis excludes Red Creek / Attachie, Noel, Tupper, Jedney, new pool delineation, and potential additional acquisitions. Tourmaline has access to significant potential Montney growth through fully delineated assets that are economic on current strip 162 87 80 65 32 110 97 75 • • 425 90 135 125 North Montney Ph1
Page 33
The Ever-Evolving Tourmaline Development Approach Mar 2025 In the Alberta Deep Basin and the BC Montney Tourmaline is constantly seeking the balance between maximizing deliverability (growth), EUR (value), and overall economic return (CF/FCF). Tourmaline ultimately prioritizes IRR maximization, this results in faster well payouts, lower supply costs, and a free cash flow flywheel that can service both capital investment and capital return in all commodity price environments. IRR EURDeliverability Longer Laterals Casing tie-ins Optimized Pad Frac Order 3d Seismic, Geosteering, Structural Optimization Maximize Liquid Prod. High Intensity Completions Downhole Chokes/Restricted Flow Wine-Racking, Cube, Mega Frac Optimize CF/FCF Maximize Earnings/ROCE Minimize Costs, Larger Pads Optimize Payout, Capital Recycling $ The Sweet Spot $ 33 4,000 5,000 6,000 7,000 8,000 9,000 10,000 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Average Lateral Feet per Well Deep Basin NEBC PRH ~50% increase in corporate lateral length since 2018 Feet
Page 34
Cost Reduction/Margin Improvement… Making the Company Better Nov 2025 • A continuous series of cost and margin improvements via the NEBC buildout in every year, 2025-2031 • Highly focused cross company cost reduction initiative including the Deep Basin • Meaningful operating cost reductions begin in 2026 with liquid margin improvements and transportation cost reductions also targeted • Additional D&C capital cost reductions for Q4 2025-1H 2026 (renegotiated contracts) • Frac sand cost reductions a NEBC focus in 2026 • Carbon tax reduction opportunities (leveraging TOU’s strong environmental performance) • Multiple initiatives and technology trials to allow the Company to continuously improve operational efficiencies • AI field trials optimizing mature production, real time operating information/new digital tools for field foremen • North Deep Basin drilling fluid trials to reduce costs/drilling times • New cost reduction technologies for the ARO program • Broad application of successful post frac drill-out methodologies 34
Page 35
Gas Development Location Inventory and Economics(1) Mar 2025 35 Notes: (1) All amounts are before tax. (2) Assumes on production date of January 1, 2025. (3) Average operating expenses over the initial five years of production. (4) Internal Rate of Return calculation is based on monthly cash flows. (5) Independent Reserve Engineer January 1, 2025 escalated price forecast, adjusted for transportation, quality and heat content. (6) See Schedule A. AB Deep Basin North & West Horizontal AB Deep Basin South Horizontal NEBC Gundy MNTN Horizontal NEBC North MNTN Horizontal NEBC South MNTN Horizontal PRH Charlie Lake Horizontal PRH Montney Horizontal Total Well Costs (Drill, Case, Complete, $ Million) 5.31 5.81 4.63 4.49 5.53 3.10 4.39 Average Reserves/Well (bcfe) 6.8 5.6 5.1 7.7 6.6 2.5 3.4 Lateral Length (metres) 2,250 2,900 2,300 2,400 2,650 2,250 2,250 Year 1 Production Rate (2) 5.4 mmcfepd 3.8 mmcfepd 4.3 mmcfepd 4.5 mmcfepd 4.4 mmcfepd 262 boepd 568 boepd Development Cost/boe $4.69 $6.20 $5.41 $3.50 $5.00 $7.53 $7.77 Operating Expenses/boe (3) $3.23 $4.92 $2.14 $6.37 $2.49 $9.10 $7.53 Net Present Value @ 10% (000's) $6,001 $6,003 $8,768 $9,012 $8,268 $4,811 $4,124 Internal Rate of Return (4) 76% 63% 338% 184% 104% 146% 124% Payback Period (months) 17 18 7 10 14 10 12 Year 1 Gas Price (5) $2.11 $2.27 $1.95 $1.90 $2.05 $2.04 $2.04 Future Development Locations (6) 14,267 527 1,188 2,901 2,820 1,274 920
Page 36
Environmental Performance Investment See Tourmaline Sustainability Report for more detail; forward looking estimates are illustrative only Mar 2025 Focusing on investment opportunities that maximize cost savings & environmental impact • Water: recycling, & pipeline infrastructure; ~95% recycling in NEBC, advancing AB towards 100% • Air: diesel displacement, pneumatic / venting reduction, power (highline), energy efficiency, CCUS, RNG, Methane ETC (Emission Testing Center) • CNG – Clean Energy / Tourmaline JV ($70mm JDA – 15-20 stations over five years) • Technology: CCUS, NGIF , RNG, other initiatives $4 $6 $4 $8 $10 $8 $6 $11 $14 $10 $17 $5 $11 $4 $15 $14 $8 $9 $17 $22 $38 $51 $- $10 $20 $30 $40 $50 $60 2019 2020 2021 2022 2023 2024 2025E 2026E Capital Investment Water Emission CNG Technology / Scalable Investment $mm/yr $40 - $60mm/yr of capital to be invested in environmental performance improvement initiatives going forward Investments to date all have made an economic return, along with lower emissions or water / land usage Future annual savings per year will far surpass investment per year; environmental investment is another source of free cash flow 36
Page 37
Environmental Performance Improvement (1) Based on an evaluation of 60 NEBC wells (2) Scope 1, using 2018 as a baseline. See sustainability report for details Mar 2025 Tourmaline has been aggressively and successfully pursuing a comprehensive environmental performance improvement strategy for over seven years. The Company is systematically improving its performance and reducing the impact of all aspects of activities upon air, land and water. 37 Achievements • 41% reduction in CO2 emission intensity since 2013; NEBC Platinum rated by Project Canary(1) • 95% of completion water recycled from gas operations • Initiation of methane reduction retrofit compliance plan in 2019; 3,700 controllers replaced • 50% reduction in surface area per producing well • Broad replacement of diesel in drilling and completion operations with natural gas • Performed lifecycle assessments of both Sundown (NEBC) & Banshee (DB) natural gas production Targets • Targeting 55% reduction in methane emission intensity from 2020 levels by 2027 • Reduce corporate emissions intensity by 25% by 2027(2), through the application of new, innovative technologies including the electrification of assets • Targeting elimination of fresh water usage in well stimulation operations (NEBC ✓) Initiatives ✓ Methane Mitigation ✓ Fuel Switching ✓ Energy Efficiency ✓ Water Recycling • Full top-down methane surveillance with aircraft & satellite. Replaced over 3,700 pneumatic devices • All drilling/frac rigs/fleets have natural gas blending, 1 highline rig, 3 battery hybrids, 1 tier 4 frac fleet • Waste heat recovery, compressor valve upgrades, battery hybrid gas plant • Produced water recycling with current capacity of 585,000 m3 across 8 water recycling facilities & 13 produced water ponds. +596% Production -41% C02e/boe ‘13 ‘23 -55% Methane Intensity by 2027 ‘20 ‘27
Page 38
$800 $2,550 $3,325 $2,262 $75 $75 $250 $250 $200 2025 2026 2027 2028 2029 2030 Total Credit Capacity 3Q25 Net Debt Debt Profile, Term, Capacity Revolving Credit Facility Additional Lines Senior Unsecured Notes Tourmaline Financial Position Excellent Liquidity, Resiliency & Capacity Commercial Paper is a month to month lending program backstopped by Revolving Credit Facility maturity. As per Tourmaline financial disclosure and the current EP Growth Plan; sensitivities are full year. Sensitivity to movement in FX may fluctuate at different forward pricing levels as a result of certain of the Company’s forei gn exchange derivative contracts. Tourmaline has ample liquidity and capacity to weather adverse commodity prices Nov 2025 $83 $67 $49 $25 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 NYMEX US$0.10/Mcf FX $0.01 Basis US$0.10/Mcf Oil US$1/bbl 2026 Cash Flow Sensitivities (All Gas) (AECO & St2) $mm Change in: Sensitivity remains primarily to natural gas 38 $mm Maturing $325 $875 Commercial Paper
Page 39
Tourmaline Technology Curve/Future Concepts, Requirements & Opportunities • Utilizing gas fired turbines to reduce costs for drilling, completions, facilities • Develop predictive reservoir/reserve tools for horizontal clastic gas wells • Refine drilling techniques/cost savings for frontal foothills Wilrich/Notikewin hz drlg • Understanding controls on Wilrich deliverability/develop predictive tools • Paleozoic/New Deep Play concepts • Improved horizontal stimulation techniques, new approaches to maximize deliverability and recovery • New shale/source rock plays • Improved Wilrich seismic imaging in strat settings and Outer Foothills settings • Cost saving via novel frac water sourcing/recycling • Alternative hz frac programs/processes – Concurrent pairs, delayed flow-backs etc. • Pasquia Hills oil shale recovery mechanisms • Ball drop/sliding sleeve completion technique in vertical wells • Novel drilling technology to reduce time/cost in drilling builds • New mud systems to reduce drilling times • AI applications in geophysical interpretation, reservoir prediction and predictive drilling problem identification. 39 • Waste heat recovery technology • Sour frac water sweetening technology
Page 40
Schedule A DRILLING LOCATIONS Estimated Drilling Inventory This presentation discloses drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 25,462 (gross) locations disclosed in this presentation, 2,229 are proved undeveloped locations, 32 are proved non-producing locations, 1,711 are probable undeveloped locations, and 21,490 are unbooked. Proved producing wells, proved undeveloped locations, proved non-producing locations, probable undeveloped locations and probable non-producing locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by GLJ and Deloitte LLP as of December 31, 2024, and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the 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 the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been derisked 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. The following provides additional information on the Company's estimation of unbooked locations. 40
Page 41
Schedule A continued 41 Deep Basin Horizontal well count : • Total horizontal Deep Basin locations = 17,660 (1-2 wells per section per zone depending on zone) • Less existing horizontals, and less 20% of existing vertical producers = 2,866 • Remaining Horizontal Locations = 14,794 Deep Basin vertical well count: • Outer Foothills gross sections = 390; 90% accessible with 2 wells per section • Less 119 Outer Foothills existing wells • Remaining vertical locations = 383 NE BC well count : • Approx. 1,226 gross sections in NE BC at 3-16 wells per sections in multiple lobes (2-6 lobes depending upon location). • Less 1,540 existing wells • Remaining NE BC Locations = 7,857 Spirit River / Peace River High well count: • Approx. 201 gross sections within the Charlie Lake Fairway x 4 wells per section (2 lobes) • Approx. 124 gross sections within the Montney Fairway x 4 wells per section per lobe (2-3 lobes) • Approx. 39 gross sections within the Wapiti Cardium Fairway x 6 wells per section • Less existing wells • Remaining Spirit River / Peace River High Locations = ~ 2,428 Total Gross Remaining Locations ~ 25,462
Page 42
Schedule B 42 Prospective locations are unbooked locations that are not included in inventory. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the 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 the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, 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 derisked 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.
Page 43
Forward Looking Information Certain information contained in this presentation constitutes forward-looking information within the meaning of applicable securities laws. This information relates to future events or the Company's future performance. All information other than information of historical fact is forward-looking information. The use of any of the words "anticipate", "plan", "contemplate", "continue", "estimate", "expect", "intend", "propose", "might", "may", "will", "shall", "project", "should", "could", "would", "believe", "predict", "forecast", "pursue", "potential" and "capable" and similar expressions are intended to identify forward-looking information. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information should not be unduly relied upon. This information speaks only as of the date of this presentation or, if applicable, as of the date specified in those documents specifically referenced herein. In addition, this presentation may contain forward-looking information attributed to third-party sources. Without limitation of the foregoing, this presentation contains forward-looking information pertaining to the following: the reserve potential of the Company's assets; the anticipated production from the Company's assets and anticipated future cash flows from such assets; the Company's growth strategy and opportunities; the Company's capital exploration and development programs and future capital requirements; the estimated quantity and value of the Company's proved and probable reserves; expectations regarding the ability to raise capital and to continually add to reserves; the Company's estimates of future interest and foreign exchange rates; the Company's environmental considerations; the Company's assumptions regarding commodity prices; the Company's expectations regarding reduction in its operating costs; the timing of commencement of certain of the Company's operations and the level of production anticipated by the Company; the potential for production disruption and constraints; supply and demand fundamentals for crude oil and natural gas; the Company's access to adequate pipeline and other gathering, transportation and processing capacity; the Company's access to third-party infrastructure; the Company's drilling and recompletion plans; the Company's expected capital expenditures; expected debt levels and credit facilities; industry conditions pertaining to the oil and gas industry; the Company's plans for, and results of, exploration and development activities; the planned construction of the Company's gathering, transportation and processing facilities and related infrastructure; the timing for receipt of regulatory approvals; the Company's treatment under governmental regulatory regimes and tax laws and potential changes in such regimes and laws; the Company's future general and administrative expenses; and the Company's expectations regarding having adequate human resource staffing. 43
Page 44
With respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: future crude oil and natural gas prices; future interests rates and currency exchange rates; the Company's ability to obtain qualified staff and equipment in a timely and cost–efficient manner; the regulatory framework governing royalties, taxes and environmental matters; the Company's ability to market production of oil and natural gas successfully; the Company's future production levels; the applicability of technologies for recovery and production of the Company's reserves; the recoverability of the Company's reserves; future capital expenditures to be made by the Company; future cash flows from production meeting the expectations stated in this presentation; future sources of funding for the Company's capital program; the Company's future debt levels; geological and engineering estimates in respect of the Company's reserves; the geography of the areas in which the Company is conducting exploration and development activities; the impact of competition on the Company; and the Company's ability to obtain financing on acceptable terms. Actual results could differ materially from those anticipated in this forward-looking information as a result of a number of factors including the risk factors set forth in the Company's reports and documents on file with Canadian securities regulatory authorities at www.sedarplus.ca or the Company's website at www.tourmalineoil.com, which risk factors should not be construed as exhaustive. See specifically "Forward-Looking Statements" and "Risk Factors" in the Company's most recently filed Annual Information Form and "Forward-Looking Statements" in the Company's most recently filed Management's Discussion and Analysis. Included in this presentation are estimates of the Company's 2026-2031 cash flow, free cash flow and cash flow per share which are based on various assumptions as to production levels, commodity prices, the anticipated receipt of drilling permits and other assumptions and in the case of the years other than 2025 or 2026, such estimates are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years' results. To the extent such estimates constitute a financial outlook, they were approved by management of the Company in November 2025 and are included to provide readers with an understanding of the Company's anticipated cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. In addition, information relating to "reserves" is deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and that the reserves described can be profitably produced in the future. See also "Statement of Reserves Data and Other Oil and Gas Information" and "Certain Reserves Data Information" in the Company's Annual Information Form. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein or otherwise and the Company undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless specifically required to do so pursuant to applicable law. Forward Looking Information 44
Page 45
Forward Looking Statement Advisories Oil and Gas Advisories Certain crude oil and natural gas liquids ("NGLs") volumes have been converted to millions of cubic feet equivalent (" mmcfe") or thousands of cubic feet equivalent ("mcfe") on the basis of one barrel ("bbl" of crude oil or NGLs to six thousand cubic feet ("mcf") of natural gas. Also, certain natural gas volumes have been converted to barrels of oil equivalent ("boe"), thousands of boe ("mboe") or millions of boe ("mmboe") using the same equivalency measure. Such equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. This presentation contains disclosure regarding finding and development costs. The aggregate of the exploration and developme nt 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. The estimated net present values disclosed in this presentation do not represent fair market value. Unless otherwise expressly stated, the information in this presentation pertaining to future drilling locations or drilling i nventories is based solely on internal estimates made by management and such locations have not been reflected in any independent reserve or resource evaluations an d have not been recognized as reserves or resources as defined in NI 51-101. See Schedule A - Drilling Locations. Similarly, unless otherwise expressly stated, the information in this presentation pertaining to targeted reserve volumes fro m future drilling is intended to indicate that in making its internal drilling decisions, the Company seeks to target drilling locations that, based on previous drilli ng results and its own internal assessments, it believes will on average ultimately generate the indicated volumes. Initial Production Rates Any references to initial production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long -term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are bas ed on field estimates and may be based on limited data available at this time. Non-GAAP and Other Financial Measures This presentation includes references to "cash flow", "capital expenditures“, “E&P capital program" and "free cash flow" which are considered "non-GAAP financial measures" and the terms "cash flow per diluted share" and "cash flow per boe" which are considered "non -GAAP financial ratios". These terms do not have a standardized meaning prescribed by GAAP. In addition, this news presentation contains the terms "adjusted working capi tal" and "net debt", which are considered "capital management measures" and do not have standardized meanings prescribed by GAAP. Accordingly, the Company’ s use of these terms may not be comparable to similarly defined measures presented by other companies. Investors are cautioned that these measures should not be construed as an alternative to or more meaningful than the most directly comparable GAAP measures in evaluating the Company's performance . Additional information on these terms are included in the Company's most recently filed Management's Discussion and Analysis (See "Non -GAAP and Other Financial Measures" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR+ website (www.sedarplus.ca) or T ourmaline's website (www.tourmalineoil.com). 45
Page 46
Forward Looking Statement Advisories Non-GAAP Financial Measures Cash Flow Management uses the term “cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company’s efficiency and its ability to generate the cash (net of current income taxes) necessary to fund its future growth expenditure s, to repay debt or to pay dividends. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. A summary of the reconciliation of cash flow from operating activities to cash flow, is set forth below: Capital Expenditures Management uses the term "capital expenditures" as a measure of capital investment in exploration and production activity, as well as property acquisitions and dispositions, and such spending is compared to the Company's annual budgeted capital expenditures. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures, is set forth below: 46 Three Months Ended September 30, Nine Months Ended September 30, (000s) 2025 2024 2025 2024 Cash flow from operating activities (per GAAP) $ 853,547 $ 727,042 $ 2,686,907 $ 2,063,670 Current tax (expenses) recovery (27,240) 16,699 (22,189) (28,508) Current taxes paid 9,204 39,259 28,136 526,802 Change in non-cash working capital (115,935) (41,100) (187,401) (193,803) Cash flow $ 719,576 $ 741,900 $ 2,505,453 $ 2,368,161 Three Months Ended September 30, Nine Months Ended September 30, (000s) 2025 2024 2025 2024 Cash flow used in investing activities (per GAAP) $ 692,374 $ 415,764 $ 2,209,673 $ 1,515,075 Change in non-cash working capital 93,463 175,154 (93,579) (73,807) Investment in long-term asset (11,800) − (11,800) − Capital expenditures $ 774,037 $ 590,918 $ 2,104,294 $ 1,441,268
Page 47
Forward Looking Statement Advisories Non-GAAP Financial Measures (con’t) E&P Capital Program Management uses the term "E&P Capital Program" as a measure of capital investment in exploration and production activity, and such spending is compared to the Company's annual budgeted exploration and production expenditures. The most directly comparable GAAP measure for exploration and production spending is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to explora tion and development expenditures, is set forth below: Free Cash Flow Management uses the term “free cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company’s efficiency and its ability to generate the cash necessary to fund its future growth expenditures, to repay debt and provide shareholder returns. Free cash flow is defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is prior to dividend payment. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. See "Non -GAAP Financial Measures – Cash Flow" and " Non-GAAP Financial Measures – Capital Expenditures" above. 47 Three Months Ended September 30, Nine Months Ended September 30, (000s) 2025 2024 2025 2024 Cash flow $ 719,576 $ 741,900 $ 2,505,453 $ 2,368,161 Capital expenditures (774,037) (590,918) (2,104,294) (1,441,268) Property acquisitions 5,140 2,123 17,283 25,704 Proceeds from divestitures (73,074) (609) (74,821) (56,834) Free Cash Flow $ (122,395) $ 152,496 $ 343,621 $ 895,763 Three Months Ended September 30, Nine Months Ended September 30, (000s) 2025 2024 2025 2024 Capital expenditures $ 774,037 $ 590,918 $ 2,104,294 $ 1,441,268 Property acquisitions (5,140) (2,123) (17,283) (25,704) Proceeds from divestitures 73,074 609 74,821 56,834 Other (16,499) (14,659) (48,855) (42,351) EP Expenditures $ 825,472 $ 574,745 $ 2,112,977 $ 1,430,047
Page 48
Forward Looking Statement Advisories Non-GAAP Financial Measures (con’t) Operating Netback Management uses the term “operating netback” as a key performance indicator and one that is commonly presented by other oil a nd natural gas producers. Operating netback is defined as the sum of commodity sales from production, premium on risk management activities and realize d gains (loss) on financial instruments less the sum of royalties, transportation costs and operating expenses. A summary of the reconciliation of opera ting netback from commodity sales from production, which is a GAAP measure, is set forth below: 48 Three Months Ended September 30, Nine Months Ended September 30, (000s) 2025 2024 2025 2024 Commodity sales from production $ 924,974 $ 935,402 $ 3,517,007 $ 3,514,721 Premium on risk management activities 427,209 300,705 1,027,464 547,677 Realized gain on financial instruments 126,814 145,986 332,168 358,556 Royalties (109,271) (105,616) (378,758) (383,553) Transportation costs (291,260) (270,327) (891,260) (805,990) Operating expenses (280,524) (249,471) (865,652) (754,947) Operating netback $ 797,942 $ 756,679 $ 2,740,969 $ 2,476,464
Page 49
Forward Looking Statement Advisories Non-GAAP Financial Ratios Operating Netback per-boe Management calculates “operating netback per-boe” as operating netback divided by total production for the period. Operating ne tback per-boe is a key performance indicator and measure of operational efficiency and one that is commonly presented by other oil and natural gas p roducers. A summary of the calculation of operating netback per boe, is set forth below: Cash Flow per-boe Management uses cash flow per boe to highlight how much cash flow is generated by each boe produced. The ratio is calculated by dividing cash flow by total production for the period. See “Non-GAAP Financial Measures – Cash Flow”. Cash Flow per diluted share Management uses cash flow per diluted share as a measurement of the Company’s efficiency and its ability to generate the cash necessary to fund its future growth expenditures, to repay debt or to pay dividends on a per diluted share basis. Cash flow per diluted share is calculated usin g cash flow divided by the weighted average diluted shares outstanding. 49 Three Months Ended September 30, Nine Months Ended September 30, ($/boe) 2025 2024 2025 2024 Revenue, excluding processing income $ 25.33 $ 26.95 $ 28.30 $ 28.29 Royalties (1.87) (2.06) (2.20) (2.45) Transportation costs (4.99) (5.27) (5.17) (5.16) Operating expenses (4.80) (4.87) (5.02) (4.83) Operating netback $ 13.67 $ 14.75 $ 15.91 $ 15.85
Page 50
Forward Looking Statement Advisories Capital Management Measures Adjusted Working Capital Management uses the term “adjusted working capital” for its own performance measures and to provide shareholders and potentia l investors with a measurement of the Company’s liquidity. A summary of the composition of adjusted working capital (deficit), is set forth below: Net Debt Management uses the term “net debt”, as a key measure for evaluating its capital structure and to provide shareholders and po tential investors with a measurement of the Company’s total indebtedness. A summary of the composition of net debt, is set forth below: 50 (000s) As at September 30, 2025 As at December 31, 2024 Working capital (deficit) $ (1,202,150) $ (167,623) Fair value of financial instruments – short-term (asset) (205,379) (315,365) Lease liabilities – short-term 8,529 8,385 Decommissioning obligations – short-term 75,000 60,000 Unrealized foreign exchange in working capital – liability (asset) (144) (15,354) Adjusted working capital (deficit) $ (1,324,144) $ (429,957) (000s) As at September 30, 2025 As at December 31, 2024 Long-term debt $ (937,623) $(1,272,775) Adjusted working capital (deficit) (1,324,144) (429,957) Net debt $(2,261,767) $(1,702,732)