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KIWETINOHK ENERGY November 2025 TSX: KEC
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Disclaimer The terms of this disclaimer and related advisories apply to the content of this presentation and any oral statements made in connection with this presentation. The sole purpose of this document is to provide an overview of Kiwetinohk Energy Corp. (the “Company” or “Kiwetinohk” or “KEC”). The information contained herein is based upon selected information provided by the Company and other sources, and is for informational purposes only. In addition, no securities commission or similar regulatory authority in Canada has reviewed or in any way passed upon this presentation and any representation to the contrary is an offence. The Company is under no obligation to provide interested parties with access to any additional information or to update any information contained herein. Neither the Company nor any of its representatives make any representation or warranty, expressed or implied, as to the accuracy or completeness of the information contained or referred to in this document or any other written or oral communication transmitted to interested parties. This presentation does not purport to contain all of the information that interested parties may require for the purposes of considering or evaluating the Company. Recipients of this document must rely solely upon their own due diligence, investigation, review and analysis. The Company and its advisors assume no responsibility or liability in connection with the preparation or provision of this document or the use of this document or any information contained herein by an interested party. This presentation includes market and industry data which was obtained from various publicly available sources and other sources believed by the Company to be true. Although the Company believes it to be reliable, the Company has not independently verified any of the data from third-party sources referred to in this presentation, analyzed or verified the underlying reports relied upon or referred to by such sources, or ascertained the underlying assumptions relied upon by such sources. The Company does not make any representation or warranty, express or implied, as to the accuracy of such information and no reliance should be placed on the fairness, accuracy, completeness or correctness of such information. The Company has no intention and undertakes no obligation to update or revise any such information or data, whether as a result of new information, future events, or otherwise, except as required by law. In this presentation, unless otherwise specified or the context requires otherwise, all dollar amounts and references to $ or C$ are references to Canadian dollars. This presentation should be reviewed in conjunction with the additional disclaimers on “Forward-looking statements”, “Reserves and oil & gas disclosure” and “Non-GAAP and other financial measures” found in the following slides. Readers are urged to review such disclaimers in their entirety. 2
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Territorial land acknowledgement Kiwetinohk means “north” or “northward” in Cree, the most widely spoken Indigenous language in Canada We acknowledge the many diverse First Nations and Métis people whose ancestors have walked the land since time immemorial. We are committed to do our part to advance reconciliation and ensure these lands are always a welcoming, healthy and prosperous place for all people who come from around the world and call them home. Together we can build great communities for today and future generations. 3
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Kiwetinohk announces a cash sale for $24.75/share under arrangement agreement with Cygnet Energy Ltd. 4 1. See “Non-GAAP and other financial measures”. 2. 2025 multiples figures based on midpoint of guidance. 3. Market capitalization based on 46.4 MM fully diluted shares outstanding. Arrangement overview 63% premium to pre-review share price EV / 2025E Production 1, 2 $41,500 ($/boe/d) EV / 2025E AFFO 1, 2 3.5x On October 28, 2025, Kiwetinohk announced an arrangement agreement with Cygnet Energy Ltd. (“Cygnet”), a private exploration and production company backed by respective investment funds managed by NGP Energy Capital Management (“NGP”), ARC Financial Corp. (“ARC Financial”), and global investment firm Carlyle (“Carlyle” NASDAQ: CG). The Arrangement marks the successful conclusion of Kiwetinohk’s business strategy review to unlock shareholder value, which was initially announced on March 5, 2025. Highlights include: ▪ All cash consideration of $24.75 per Share, provided primarily by NGP and Carlyle. The Arrangement is not subject to any financing conditions. ▪ Independent review through a Special Committee of independent directors. ▪ Formal Valuation and Fairness Opinions received from Peters & Co. Limited with the fair market value in the range of $22.00 and $27.00 per Share. ▪ Strong support with unanimous approval from the Special Committee, the Board of Directors and approximately 79% of the outstanding shares including 38% of the minority shareholders, subject to customary fiduciary protections. ▪ The Arrangement is expected to close in December 2025 and is subject to certain closing conditions including a shareholder vote as described in the news release. $15.20 $24.75 $0 $10 $20 $30 Pre-review (Mar 5, 2025) Transaction Price (Oct 27, 2025) Enterprise value ($billions) $1.1 $0.3 $1.4B Market Capitalization Net Debt
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TOP-TIER KAYBOB DUVERNAY OPERATOR Executed top 8 wells in Duvernay shale KEC has 9 of the top 10 and 38 of the top 100 producing Duvernay wells Drilled the longest single-leg horizontal well in Canadian history at 9,500 m EXCITING NEW TURBIDITE MONTNEY PLAY Recent results exceeding 1,700 boe/d average peak 30-day rates (~25%-35% liquids) New wells on track for flat production profiles for >8 months EXTENSIVE RUNNING ROOM 182 Duvernay and 247 Montney net wells in inventory Only ~40% booked, generating a ~24-year 2P Reserve Life Index OWNED AND OPERATED INFRASTRUCTURE Robust operating structure driving peer-leading netbacks ($31.37/boe in Q3 2025) and operating costs of ~$6/boe (37% since 2022) STRATEGIC CONTRACTED U.S. EGRESS 120 MMcf/d capacity on Alliance Pipeline enabling premium market access Higher gas price realizations relative to local markets (~200% premium over last 7 quarters) Alliance contract extended to 10-year term (to 2035) with tolls reduced to $0.95/Mcf (effective Nov 2025) SIGNIFICANT FFF WHILE DELIVERING GROWTH 2025E 20%+ YoY production growth ~$119 MM of free funds flow expected in 2025 2 5 Why invest in Kiwetinohk? 1 1. See “Forward-looking statements”, “Reserves and oil & gas disclosure” and “Non-GAAP and other financial measures”. 2. 2025E free funds flow forecasted to be ~$119 MM at October 23, 2025 strip prices . See slide for full guidance summary and sensitivities in the appendix.
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Multi-year performance & outlook 6 1. 2022A through 2025E. 2. 2025E free funds flow forecasted to be ~$119 MM at October 31, 2025 strip prices . See “Non-GAAP and other financial measures” and slide for full guidance summary and sensitivities in the appendix. Continued double-digit production growth Majority of capital dedicated to DCET Inflection point on FFF in 2025 Infrastructure in place to support ~40,000 boe/d ~$20 MM DCET savings in 2025 from lower well costs and efficient drilling and completion execution Free funds flow potential to grow with production ($100) ($50) $0 $50 $100 $150 2022 2023 2024 2025E ($MM) Free Funds Flow 2 $0 $100 $200 $300 $400 2022 2023 2024 2025E ($MM) Upstream Capital 0 10,000 20,000 30,000 40,000 2022 2023 2024 2025E (boe/d) Production
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2025 guidance summary 1 As of Nov 4, 2025 7 OPERATIONAL & FINANCIAL DETAILS Average Sales Volumes (Mboe/d) 33.0 – 34.0 Oil & Liquids % (%) 45% – 49% Royalty Rate (Crown) (%) 5% – 6% Operating Expense ($/boe) $6.00 – $6.25 Transportation Expense ($/boe) $5.25 – $5.50 Corporate G&A Expense 2 ($/boe) $1.95 – $2.15 Upstream Capital ($MM) $280 – $288 DCET ($MM) $265 – $273 Plant expansion, production maintenance and other ($MM) $15 1. See “Non-GAAP and other financial measures”. 2. Includes G&A expenses for all divisions of the Company: corporate, upstream, power and business development. 3. WTI and HH prices denoted in USD. 2025 SENSITIVITIES Adjusted Funds Flow from Operations Strip (October 31) US$61/bbl WTI & US$3.75/MMBtu HH ($MM) $395 – $410 Net Debt to Adjusted Funds Flow from Operations Strip (October 31) US$61/bbl WTI & US$3.75/MMBtu HH (X) 0.4x 2025E adjusted funds flow sensitivities 1, 3 FFF positive at $50 WTI & $2.50 HH after maintenance and growth capex FFF positive at $50 WTI & $2.50 HH after maintenance and growth capex $50 WTI / $2.50 HH October 31 Strip Base Maintenance Capex Growth Capex Free Funds Flow 0 50 100 150 200 250 300 350 400 450 AFF Uses of Cash C$MM
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Extensive running room in Duvernay and Montney 1 1. See “Forward-looking statements” and “Reserves and oil & gas disclosure”. Fox Creek area map 8 YE2024 Duvernay Montney Total Company Inventory 182 247 429 Breakdown Inventory rich Drilling to fill High value production 429 future Duvernay and Montney locations 40 Mboe/d owned and operated infrastructure capacity Diverse commodity mix providing portfolio optionality Booked inventory generates 2024 YE 2P RLI of ~24 years Planning to bring on 17 new wells in 2025 ~50% of production is oil, condensate and NGLs Inventory spans from <100 to >1,000 bbls/MMcf Placid Tony Creek South Simonette Proved UnbookedProbable KEC Montney KEC Duvernay KEC Duvernay & Montney 2025 Montney plan 2025 Duvernay plan KEC WI Gas Facility
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1. Targeted IRR is before tax and estimated at US$70 WTI and US$4.00 HH. See “Reserves and oil & gas disclosure”. 2. Based on total inventory (booked + unbooked) within Simonette Montney and Placid Montney. Assumes capital deployment of ~8 -12 wells per year and availability of required egress and processing capacity. Estimates include assumptions consistent with curre nt Montney development program and type curves which may not be achieved as forecasted. See “Forward-looking statements” and “Reserves and oil & gas disclosure”. 9 Tony Creek Duvernay Placid Montney Simonette Duvernay & Montney CO-DEVELOPMENT AREA KEC Montney KEC Duvernay Co-development area KEC WI Gas Facility Montney delineation underway through Duvernay co-development up to 1,700 boe/d peak 30-day rates (25%-35% liquids) 6 Montney wells on-stream in 2025 ~76% of total Montney locations unbooked ~$10-12 MM lower relative DCET per well 60%-150%+ targeted ½-cycle IRRs 1 ~25 Mboe/d potential to grow Montney production over next decade 2 Extensive Montney inventory offers reserves and production upside Vast Montney resource overlapping core Duvernay inventory with ample running room Operational synergies and cost savings leveraging existing pad locations and surface facilities Recent well results outperforming expectations, demonstrating repeatable growth potential
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New well results 1 10 🅓 01-18 pad (very rich gas) New wells 2 MTNY + 1 MTNY DUC On-stream Q3 2025 Avg peak 30-day rate ~1,140 boe/d Oil & Condensate % 56% 🅒 09-33 pad (volatile oil) New wells 3 DUV On-stream May 2025 Avg peak 30-day rate ~1,320 boe/d Oil & Condensate % 73% 1. See “Forward-looking statements” and “Reserves and oil & gas disclosure”. 🅐 09-11 pad (very rich gas) Wells 3 DUV On-stream Dec 2024 Avg peak 30-day rate ~2,850 boe/d Oil & Condensate % 56% New wells 3 DUV On-stream Q4 2025 🅑 14-29 pad (very rich gas) New wells 2 DUV On-stream Feb 2025 Avg peak 30-day rate ~2,230 boe/d Oil & Condensate % 49% New well 1 MTNY On-stream Feb 2025 Avg Peak 30-day rate ~1,920 boe/d Oil & Condensate % 36% Tony Creek South Simonette Placid A B D Fox Creek C E 🅔 01-27 pad (very rich gas) New wells 2 DUV On-stream Q3 2025 Avg peak 30-day rate ~2,650 boe/d Oil & Condensate % 57% New well 1 MTNY On-stream Q3 2025 Avg peak 30-day rate ~1,270 boe/d Oil & Condensate % 39% KEC Montney KEC Duvernay KEC Duvernay & Montney 2025 Montney plan 2025 Duvernay plan KEC WI Gas Facility
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Consistently executing top producing Duvernay wells in Western Canada 1 11 1. Includes all Duvernay wells on-stream as of September 2025. Forecast data provided by Turing Analytics, Inc. Volumes from Petrinex data, using sales gas volumes, C2-C4 volumes and a combination of sales condensate, oil and C5. KEC has 9 of the top 10 and 38 of the top 100 producing Duvernay wells Strong performance from combination of leading methods and leading assets All top 100 wells located in Kaybob KEC C5 KEC GAS PEER 1 PEER 2 PEER 3 OTHER PEERS 0 500 1,000 1,500 2,000 2,500 3,000 IP180F Sales Rate (Condensate bbl/d, Gas and NGLs boe/d) KEC has top decile performance among all Duvernay wellsKEC has top decile performance among all Duvernay wells
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12 1. See “Forward looking statements”. 2. Calculated based on 120 MMcf/d of contracted capacity utilizing strip pricing as of October 31, 2025 and offset by incremental costs incurred to transpor t product to Chicago vs AECO. AECO 5A C$/mcf pricing converted based on heating value of 1,150 btu/scf. 3. The Company has a commitment on the Alliance pipeline until October 2035.. 4. See “Forward looking statements”. Chicago-AECO premium based on long-term basis differential of US$1.55/MMbtu as of October 31, 2025 strip. Converted to C$/mcf using a 0.73 USD/CAD FX rate and gas heating value of 1,150 btu/scf. Excluding one time $8 MM refund anticipated in 2026. Realized ~200% above AECO over last 7 quarters 2 120 MMcf/d of capacity on Alliance Pipeline with >90% of KEC gas production sold in Chicago (5th largest shipper) ~$85 MM of value expected in 2025 1, 2 2035 Alliance contract extended 10 years (through Oct 2035) 3 ~$1.50/Mcf of estimated annual value from 2026 - 2035 4 Infrastructure -advantaged business strategy $0 $1 $2 $3 $4 $5 $6 $7 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2024 2025 Realized Gas Price (C$/Mcf) KEC AECO 5A $0 $2 $4 $6 $8 $10 2022 2023 2024 2025E Operating Expense ($/boe) ▼37% decrease in per unit opex since 2022 Owned infrastructure supports strong opex 1 Northern Virginia (world’s largest data center market) ~521% premium in Q3 2025
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High gas realizations drive resilient peer -leading netbacks 1. See “Non-GAAP and other financial measures”. 2. Source: Peters & Co. Limited estimates and company reports. Peer group consists of ARX, BIR, KEL, LGN, NVA, PEY, SDE, TOU and YGR. Pricing and netback definitions may vary between public disclosures,. 13 11 quarters of top-tier netbacks 1 Realized natural gas prices vs. peers Q2 2025 2 $31.37/boeAverage $31.91/boe $0 $15 $30 $45 $60 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2023 2024 2025 Operating Netback ($/boe) Operating netback Average realized prices Average operating netback $0 $10 $20 $30 $40 $50 $0 $1 $2 $3 $4 $5 Operating Netback ($/boe) Realized Gas Price (C$/Mcf) Peers AECO Daily Q2 Average Q2 2025 Netback KEC
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Expecting 20%+ production growth while generating strong FFF 1 1. See “Forward-looking statements” and "Non-GAAP and other financial measures“. KEC production growth and FFF yields based on midpoint of guidance and October 31, 2025 share price close of $ 24.54/share. Peer data sourced from Capital IQ consensus mean estimates (October 31, 2025). Peers include AAV, ARX, BIR, BTE, HWX, NVA, PEY, SGY, TOU and TVE. 14 31% 18% 17% 17% 16% 14% 13% 12% 11% 10% 6% (10%) 0% 10% 20% 30% 40% KEC Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 YoY Production Growth + FFF Yield 2025E Production Growth FFF Yield KEC KEC offers attractive 2025 growth and FFF profile KEC offers attractive 2025 growth and FFF profile
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15 2025 Environment, Social & Governance highlights 1 On track for 50% reduction in vented methane by 2025 (18,914 tCO2e in 2023 from 2022 baseline of 28,177 tCO2e) Governance Social Environmental Spent over 3x the Alberta Energy Regulator’s mandatory ARO expenditures One lost-time injury Ongoing retention in our Indigenous operator trainee program More funds to businesses from our Microloan fund in partnership with Indian Business Corp to support small businesses Spent >$3.2MM with band-owned and privately-owned Indigenous businesses Majority independent board & audit committee Anonymous Whistleblower Policy Insider shareholder ownership Strong industry experience in energy and utilities sector Achieved Level 5 in 2025 (for the 2024 reporting year) 1. Includes reporting data for calendar year 2024. Code of Conduct ▼55% reduction in vented methane since 2022, achieving target ahead of schedule Vented methane of 12,740 tCO2e in 2024 vs 2022 baseline of 28,177 tCO2e. (Total 2024 emissions increased from 207,675 tCO2e to 209,793 tCO2e in 2024 with 19% higher production). CO2 Since 2019, reconnected >600km of fish habitat by replacing watercourse crossings on native trout streams 44% Female senior leadership 22% Visible minorities in senior leadership 5% Indigenous staff 30% Female board representation 20% Visible minority board representation
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APPENDIX
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17 Ample infrastructure and takeaway for continued growth Fox Creek area map 120 MMcf/d 30 MMcf/d Alliance Pipeline capacity access to US gas markets held until 2035 NGTL capacity incremental egress to local markets KEC 10-29 Gas Plant KEC 05-31 Gas Plant Bigstone (Peyto-operated) 14-28 Gas Plant KEC 07-11 Amine Facility Pembina GI K3 03-15 Gas Plant Simonette Tony Creek Placid KEC Montney KEC Duvernay KEC Duvernay & Montney KEC Pipelines Third Party Pipelines Market Gas Market Crude OilKEC WI Gas Facility Kiwetinohk gas plants connect to both the Alliance Pipeline and the NGTL system where gas can be sold to Chicago or AECO Kiwetinohk gas plants connect to both the Alliance Pipeline and the NGTL system where gas can be sold to Chicago or AECO Simonette Placid 100% KEC owned gas plants 100% KEC owned facility & Non-op WI in Peyto 14-28 plant KEC WI % 100% >98% run-time 39.3% (non-op) where majority of Montney gas volumes are processed Capacity 10-29 plant: 90 MMcf/d 05-31 plant: 45 MMcf/d 80 MMcf/d Liquids Capacity 18,000 bbl/d includes C5+ stabilization —
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18 1. Market capitalization calculated based on closing price of the last trading day of Q3 2025 (September 30, 2025), share price of $23.16 / share. 2. Includes all units outstanding under the equity-settled incentive plans. 3. Net debt as of September 30, 2025. See “Non-GAAP and other financial measures”. 4. Insider ownership calculated based on management and directors and shareholders with >10% ownership. TSX: KEC Corporate profile CAPITALIZATION (AS AT Q3 2025) Basic Shares Outstanding (MM) 43.8 Market Capitalization 1 ($MM) $1,014 Dilutive Securities 2 (avg. exercise price of $17.28/sh) (MM) 9.4 Net Debt 3 ($MM) $179 Enterprise Value ($MM) $1,193 Credit Facility Limit ($MM) $400 EDC Letter of Credit Facility Limit ($MM) $100 Tax Pools ($MM) $836.7 COMMON SHARE OWNERSHIP (AS AT Q3 2025) ANALYST COVERAGE ATB Capital Markets Amir Arif BMO Capital Markets Jeremy McCrea National Bank Dan Payne Peters & Co. Limited Conrad Bereznicki, Ken Chmela RBC Capital Markets Michael Harvey, Maurice Choy INVESTOR RELATIONS Email: IR@kiwetinohk.com CORPORATE CALENDAR Shareholder vote ~Dec 16, 2025 ARC 62.9% Luminus 11.9% Management and Directors 3.8% Other 21.4% ~79% insider ownership 4 $10 $12 $14 $16 $18 $20 $22 $24 $26 Stock Price (C$/share)
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Hedging summary As at Nov 5, 2025 19 3Q25 4Q25 1Q26 2Q26 3Q26 4Q26 1Q27 2Q27 3Q27 4Q27 1Q28 WTI HEDGES WTI Swap Volumes (bbl/d) - 1,000 750 750 750 750 250 250 250 - - WTI Buy Put Volumes (bbl/d) - 4,833 3,750 3,583 3,000 3,000 1,917 1,333 1,250 1,250 250 WTI Sell Call Volumes (bbl/d) - 3,833 2,500 2,333 2,250 2,250 1,167 583 500 500 - WTI Swap Price (US$/bbl) - $70.04 $68.72 $68.72 $68.72 $68.72 $66.05 $66.05 $66.05 - - WTI Buy Put Price (US$/bbl) - $62.96 $60.33 $60.35 $61.25 $61.25 $54.79 $52.83 $53.00 $53.00 $55.00 WTI Sell Call Price (US$/bbl) - $74.29 $72.35 $72.19 $72.11 $72.11 $72.10 $74.23 $75.00 $75.00 - ALLIANCE HEDGES Henry Hub Buy Put Volumes (MMBtu/d) - 68,333 60,000 52,500 52,500 50,833 27,500 24,167 22,500 22,500 6,667 Henry Hub Sell Call Volumes (MMBtu/d) - 65,833 57,500 52,500 52,500 50,833 27,500 24,167 22,500 22,500 6,667 Henry Hub Buy Put Price (US$/MMBtu) - $3.33 $3.26 $3.24 $3.24 $3.24 $3.45 $3.45 $3.44 $3.44 $3.52 Henry Hub Sell Call Price (US$/MMBtu) - $4.62 $4.56 $4.48 $4.48 $4.46 $4.75 $4.80 $4.82 $4.82 $4.89 ALLIANCE REPLACEMENT GAS HEDGES Bought AECO 5A Sold at Henry Hub (MMBtu/d) - 15,000 10,000 10,000 10,000 3,333 - - - - - GDD Chicago Sold at Henry Hub (MMBtu/d) - (15,000) (10,000) (10,000) (10,000) (3,333) - - - - - AECO 5A To Henry Hub Basis (US$/MMBtu) - ($1.91) ($2.19) ($2.19) ($2.19) ($2.19) - - - - - GDD Chicago to Henry Hub Basis (US$/MMBtu) - ($0.14) ($0.18) ($0.18) ($0.18) ($0.18) - - - - - FX HEDGES FX Notional Swaps (monthly average) (US$MM) $12.5 $12.5 $0.0 $0.0 $0.0 $0.0 $3.0 $3.0 $3.0 $3.0 - FX Buy Put (US$MM) $10.5 $10.5 $15.0 $15.0 $15.0 $15.0 $10.0 $10.0 $10.0 $10.0 - FX Sell Call (US$MM) $10.5 $10.5 $19.0 $19.0 $19.0 $19.0 $10.0 $10.0 $10.0 $10.0 - FX Swap Rate (CAD/USD) 1.35 1.35 - - - - 1.35 1.35 1.35 1.35 - FX Average Floor (CAD/USD) 1.36 1.36 1.32 1.32 1.32 1.32 1.34 1.34 1.34 1.34 - FX Average Ceiling (CAD/USD) 1.42 1.42 1.40 1.40 1.40 1.40 1.40 1.40 1.40 1.40 -
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Forward -looking statements 20 Certain statements contained in this presentation constitute “forward-looking statements” or “forward-looking information” within the meaning of applicable securities legislation (collectively, “forward-looking statements”). All statements other than statements of historical fact are forward-looking statements. The use of any of the words “anticipate”, “achieve”, “plan”, “target”, “execute”, “upside”, “forecast”, “continue”, “estimate”, “expect”, “may”, “will”, “should”, and “potential” and similar expressions or statements regarding an outlook are intended to identify forward-looking statements. These statements involve 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 statements. No assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this presentation should not be unduly relied upon. Events or circumstances may cause actual results to differ materially from those predicted as a result of numerous known and unknown risks, uncertainties and other factors, many of which are beyond the control of the Company. These statements speak only as of the date of this presentation. In addition, this presentation may contain forward- looking statements attributed to third-party industry sources. Specifically, this presentation contains forward-looking statements pertaining to: upstream production growth; priorities for capital allocation; the Company’s growth strategy and prospects including the Company’s operational and financial guidance for 2025; the anticipated completion of certain wells, the timing thereof and the production therefrom; expectations regarding the Company’s plans to drill wells; expectations regarding the development of the Company’s Duvernay and Montney inventory; expectations of a reduction in Alliance Pipeline tolls to take effect in November 2025; the Company’s ability to co-develop Montney inventory with Duvernay in Simonette using existing infrastructure; the potential growth of Montney production; continued growth of the turbidite Montney play; inventory and infrastructure in place to develop upstream resources to 40,000 boe/d, and the Company’s ability to achieve its target of 40,000 boe/d; expectations regarding CAGR targets; expectations relating to the Company’s capital expenditures and the resulting growth therefrom; expected free funds flow, production and output; the Company’s ability to fill egress commitments; the Company’s plans for exploration, resource testing, development, and exploitation; projections of market prices and costs; access to gas sales on the Chicago market and other market access; nature, timing and development of the Company’s capital projects, including the expected financial performance thereof following completion of the development and the commencement of operations, as applicable; production, capex, and free funds flow outlook; the Company’s ability to maintain both free funds flow and growth; estimates of operating netback; the Company’s plans with respect to development and operation of its upstream properties, including estimates of production, drilling and completion costs and efficiency improvements; the replacement of watercourse crossings; expectations with respect to the Company’s financial position; future costs; access to third-party infrastructure; industry conditions pertaining to the crude oil and natural gas industry and the energy transition and renewable power industries; expectations regarding the Company’s power division, carbon hubs and access to diverse markets for its products; the expected timing for holding the Special Meeting; the expected timing for closing the Arrangement; the consideration and expected benefits to be received by Kiwetinohk Shareholders pursuant to Arrangement; the expectation of satisfying all conditions of closing; the expectation that the Circular will be filed on SEDAR+ when available; and the outcome of the current business strategy review. Statements relating to “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estima tes provided herein. In addition, this presentation contains certain forward-looking information relating to economics for drilling opportunities in the areas that the Company has an interest. Such information includes, but is not limited to, recycle ratios, reserve life index , anticipated netbacks, EV/DACF and capex ratios which are based on additional various forward-looking information such as production rates, anticipated well performance, the estimated net present value of the anticipated future net revenue associated with the wells, anticipated reserves, anticipated capital costs, anticipated finding, exploration and development costs, anticipated ultimate reserves recoverable, anticipated future realized hedging gains and losses, anticipated future royalties, operating expenses, transportation expenses and anticipated construction and operation of power generation facilit ies.
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In addition to other factors and assumptions that may be identified in this document, assumptions have been made regarding, among other things: the expectation of 90% of natural gas sales being directed to the Chicago market during 2025; the timing and costs of the Company’s capital projects, including drilling and completion of certain wells; costs to abandon wells or reclaim property; the ability of the Company to mitigate the cost of transportation services in excess of current production needs; the impact of increasing competition; general business, economic and market conditions; the general stability of the economic and political environment in which the Company operates; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the operator of the projects that the Company has an interest in to operate in a safe, efficient and effective manner; future commodity and power prices; currency, exchange, royalty and interest rates; near and long-term impacts of tariffs or other changes in trade policies in North America, as well as globally; Company’s unique position to deliver additional value to shareholders; the regulatory framework regarding royalties, taxes, power, renewable and environmental matters in the jurisdictions in which the Company operates; the ability of the Company to obtain the required capital to finance its exploration, development and other operations and meet its commitments and financial obligations; the ability of the Company to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities; anticipated timelines and budgets being met in respect of drilling and completions programs and other operations; the impact of natural disasters, war, hostilities, civil insurrection, pandemics, instability and political and economic conditions (including the ongoing Russian-Ukrainian conflict and conflict in the Middle East) on the Company; the ability of the Company to successfully market its products; the Company’s operational success and results being consistent with current results and/or expectations; the Company’s future production levels and future cash flows thereof; the recoverability of the Company’s reserves; 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 and the access, economic, regulatory and physical limitations to which the Company may be subject from time to time community and stakeholder commitment to sustainable energy sources; the Company’s positioning within the sustainable energy or energy transition space; the Company’s ability to achieve certain of its ESG initiatives; risks related to the interpretation of, and/or potential claims made pursuant to, the Government of Canada amendments to the deceptive marketing practices provisions of the Competition Act (Canada) regarding greenwashing; the impact of rising inflation rates and interest rates on the North American and world economies and the corresponding impact on the Company’s supply chain, costs and profitability, and on crude oil, NGLs and natural gas prices; the Company’s ability to obtain the support of stakeholders other than regulators which may affect the Company’s ability to efficiently develop its capital projects including the cost or timing thereof; the legislation and regulations impacting the Company’s operations thereof and the interpretation thereof; and the Company’s ability to obtain financing necessary for the advancement of the Company’s business plan on acceptable terms. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions that have been used. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements as the Company can give no assurance that such expectations will prove to be correct. Forward-looking statements or information involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties include, among other things: failure to obtain or satisfy, in a timely manner or otherwise, required Kiwetinohk Shareholder and court approvals and other conditions to the closing of the Arrangement; the risk that the ongoing Canada Post labour dispute may impact, prevent or delay delivery of the Circular and other meeting materials for the Special Meeting to Kiwetinohk Shareholders; the risk that competing offers or acquisition proposals will be made; the negative impact that the failure to complete the Arrangement for any reason could have on the price of the Shares or on the business of Kiwetinohk; the failure of the Purchaser to satisfy the closing conditions thereunder in a timely manner or at all; the Purchaser’s failure to pay the cash consideration at closing of the Arrangement; the business of Kiwetinohk may experience significant disruptions, including loss of clients or employees due to Arrangement related uncertainty, industry conditions or other factors; risks relating to employee retention; the risk of regulatory changes that may materially impact the business or the operations of Kiwetinohk; the risk that legal proceedings may be instituted against Kiwetinohk; risks related to the diversion of management’s attention from Kiwetinohk’s ongoing business operations while the Arrangement is pending; the ability of management to execute its business plan; general economic and business conditions; risks of natural disasters, war, hostilities, civil insurrection, pandemics, instability and political and economic conditions (including the ongoing conflict in the Middle East and the Russian-Ukrainian conflict) in or affecting jurisdictions in which the Company operates; the risks of the power and renewable industries; operational and construction risks associated with certain projects; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks relating to regulatory approvals and financing; uncertainty involving the forces that power certain renewable projects; uncertainty regarding provincial and federal electricity regulations and policies; the Company’s ability to enter into or renew leases; potential delays or changes in plans with respect to power and solar projects or capital expenditures; risks associated with rising capital costs and timing of project completion; fluctuations in commodity and power prices, foreign currency exchange rates and interest rates; inflation and increased pricing and costs for services, personnel and other items; risks inherent in the Company’s marketing operations, including credit, health, safety, environmental, market and construction risks and risks associated with existing and potential future lawsuits and regulatory actions against the Company; uncertainties as to the availability and cost of financing; the ability to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms; processing, pipeline and fractionation infrastructure outages, disruptions and constraints; financial risks affecting the value of the Company’s investments; and other risks and uncertainties described elsewhere in this document and in Kiwetinohk’s other filings with Canadian securities authorities. 21 Forward -looking statements (continued)
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22 Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. Additional information on risks, uncertainties and assumptions can be found under “Risk Factors” in the Company’s annual information form (“AIF”) for the year ended December 31, 2024, published on the Company’s profile on the System for Electronic Document Analysis and Retrieval (“SEDAR+”) at www.sedarplus.ca. The forward-looking statements and information contained in this document speak only as of the date of this document and the Company undertakes no obligation to publicly update or revise any forward-looking statements or information, except as expressly required by applicable securities laws. This presentation includes information obtained from independent industry publications, government publications, market research reports and other published independent sources. Such publications and reports generally state that the information contained therein has been obtained from sources believed to be reliable. Although the Company believes these publications and reports to be reliable, it has not independently verified any of the data or other statistical information contained therein, nor has it ascertained or validated the underlying economic or other assumptions relied upon by these sources. Future-Oriented Financial Information This document contains information that may constitute future-orientated financial information or financial outlook information (collectively, “FOFI”) about the Company’s prospective financial performance, financial position or cash flows, all of which is subject to the same assumptions, risk factors, limitations and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise or inaccurate and, as such, undue reliance should not be placed on FOFI. The Company’s actual results, performance and achievements could differ materially from those expressed in, or implied by, FOFI. These projections may also be considered to contain future oriented financial information or a financial outlook. See above and “Risk Factors” in the Company’s AIF for the year ended December 31, 2024, published on the Company’s profile on SEDAR+ at www.sedarplus.ca for a further discussion of the risks that could cause actual results to vary. The future oriented financial information and financial outlooks contained in this presentation have been approved by management as of the date of this presentation. The Company has included FOFI in order to provide readers with a more complete perspective on the Company’s future operations and management’s current expectations relating to the Company’s future performance. Readers are cautioned that such information may not be appropriate for other purposes. Unless required by applicable laws, the Company does not undertake any obligation to publicly update or revise any FOFI statements, whether as a result of new information, future events or otherwise. Forward -looking statements (continued)
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Barrel of Oil Equivalency For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. The term “boe” may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas per barrel of oil (6 mcf:1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from an energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be misleading as an indication of value. Emissions There is no single standard system that applies across companies for compiling and calculating the quantity of greenhouse gas emissions (“GHG Emissions”) and other sustainability metrics attributable to the Company’s operations. Accordingly, such information may not be comparable with similar information reported by other companies. The Company’s Scope 1 and Scope 2 GHG Emissions are calculated using locally regulated methodology or locally recognized industry standards as well as Global Waste Research Institute/World Business Council for Sustainable Development GHG Protocol. The Company may change its policies for calculating these GHG emissions and other sustainability metrics in the future without prior notice. Industry Specific Terminology This presentation contains certain metrics commonly used in the oil and gas industry, such as “30-day rates”, “IRRs” “operating netback”, “IP180”, “DCET”, “peak rates”, “PDP”, “TP”, “TPP” “recycle ratio”, “BT reserves”, “reserve life index”, “reserves replacement” (excluding A&D), “F&D”, “FD&A” and “capital efficiency”. These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies. Therefore, they should not be used by investors to make such comparisons. The Company calculates these metrics according to the descriptions below and in the “Non-GAAP and other financial measures” section of this presentation. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s performance over time; however, such measures are not reliable indicators of the Company’s future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon. BT reserves refers to the before tax value of the Company’s reserves as reported in the McDaniel Reserves Report. Reserve replacement (excluding A&D) is calculated by dividing: (i) the net changes to reserves in such reserves category from the prior period from extensions & improved recovery, technical revisions, economic factors, acquisitions, and dispositions, expressed in boe; by (ii) the actual annual production for the year. Reserve life index is calculated by dividing: (i) the reserves by category, expressed in boe; by (ii) the annualized fourth quarter average production rate, expressed in boe/d. It is an indication of how long an exploration and production company can sustain current rates of production based on proved reserves. Recycle ratio is calculated by dividing the netback (a non-GAAP financial measure) per boe for the period by the F&D costs or the FD&A costs for the period. Recycle ratio is used by investors and management to compare the cost of adding reserves to the netback realized from production. 23 Reserves estimates in this presentation are based on the evaluation prepared by McDaniel as set out in its report effective as of December 31, 2024 (the “McDaniel Reserves Report”), which was prepared in accordance with National Instrument 51- 101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook. The McDaniel Reserves Report was based on the average forecast pricing of McDaniel, GLJ Ltd. and Sproule Associates Limited and inflation rates and foreign exchange rates as at January 1, 2025, which is available on McDaniel’s website at www.mcdan.com. The discounted and undiscounted net present value of future net revenues attributable to the Company’s reserves do not represent the fair market value of the Company’s reserves. CRUDE OIL / CONDENSATE (MMBBL) NGLS (MMBBL) NATURAL GAS (BCF) TOTAL (MMBOE) 1 Proved Developed Producing 13.2 6.1 147.9 44.0 Total Proved 44.0 17.3 416.3 130.7 Total Proved plus Probable 80.9 33.1 794.6 246.4 Reserves and oil & gas disclosure
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Reserves and oil & gas disclosure (continued) Short-Term Production rates and IRR References in this presentation to “peak rates”, “IRR”, “<30-day rates”, “IP 180” and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter, and are therefore not indicative of long-term performance or recovery. Investors are encouraged not to place reliance on such rates when assessing the Company’s aggregate production or long-term production. Drilling Locations This presentation discloses drilling locations or inventory. The table below shows the total locations broken down into proved locations, probable locations and unbooked locations. Proved locations and probable locations are derived from McDaniel’s reserves evaluation 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. Unbooked locations consist of drilling locations that 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 of these drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources, or production. The drilling locations on which the Company drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and additional reservoir information that is obtained, and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and, if drilled, there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Production and Production Type Information References to crude oil, natural gas liquids, natural gas and average daily production in this presentation refer to the light and medium crude oil, tight crude oil, conventional natural gas, shale gas and NGLs product types, as applicable, as defined in NI 51-101. NI 51-101 includes condensate within the NGLs product type. The Company has disclosed condensate as combined with crude oil and separately from other NGLs since the price of condensate as compared to other NGLs is currently significantly higher, and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom. Crude oil therefore refers to light oil, medium oil, tight oil, and condensate. Notwithstanding the foregoing, the Company’s amount of crude oil that constitutes light oil, medium oil and tight oil is immaterial, and the majority of KEC’s crude oil is comprised of condensate. NGLs refers to ethane, propane, butane, and pentane combined. Natural gas refers to conventional natural gas and shale gas combined. 24 TOTAL MONTNEY TOTAL DUVERNAY TOTAL COMPANY PROVED LOCATIONS, NET 32 73 105 PROBABLE LOCATIONS, NET 27 42 69 UNBOOKED LOCATIONS, NET 188 67 255 TOTAL LOCATIONS, NET 247 182 429
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25 Throughout this document and in other materials disclosed by the Company, the Company uses various specified financial measures including “non-GAAP financial measures”, as defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure (“NI 52-112”) and explained in further detail below, including “capital expenditures”, and “operating netback” (collectively, “Non-GAAP Measures”). The most directly comparable GAAP measure to capital expenditures is “cash flow used in investing activities”. The most directly comparable GAAP measure to operating netback is “commodity sales from production”. The Non-GAAP Measures presented in this document should not be considered in isolation or as a substitute for performance measures prepared in accordance with IFRS and should be read in conjunction with the Company’s Condensed Consolidated Interim Financial Statements as at and for the three and nine months ended September 30, 2025 (the “Financial Statements”) and the Company’s Management’s Discussion and Analysis for the three and nine months ended September 30, 2025 (“MD&A”). Readers are cautioned that these Non-GAAP Measures do not have standardized meanings and should not be used to make comparisons between Kiwetinohk and other companies. See the heading “Non-GAAP and other financial measures” in the MD&A, available on SEDAR+ at www.sedarplus.ca and incorporated by reference into this presentation, for a detailed analysis, calculation and reconciliation of the Non-GAAP Measures. Supplementary Financial Measures The presentation contains a number of supplementary financial measures, including net present value (“NPV 10”, “NPV 15” and “NPV 20”), which does not have standardized meaning or a standard method of calculation and therefore may not be comparable to similar measures used by other companies. Such metrics have been included to provide users with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to performance in previous periods. Therefore, such metrics should not be unduly relied upon. NPV 10, NPV 15 and NPV 20 are the differences between the present value of cash inflows and the present value of cash outflows over a period of time at a 10%, 15% and 20% discount rate, respectively. Management uses this finance metric for its own performance measurements and to provide investors with measures to compare the Company’s economic returns and operations over time. Readers are cautioned that the information provided by this metric, or that can be derived from this metric, as presented herein, should not be relied upon for investment or other purposes. This presentation contains supplementary financial measures expressed as: (i) adjusted funds flow, operating expenses, transportation, and corporate general and administrative expense on a $/boe basis and (ii) royalty rate. Metrics presented on a $/boe basis are calculated by dividing the respective measure, as applicable, over the referenced period by the aggregate applicable units of production (boe) during such period. Royalty rate is calculated by dividing royalties by petroleum and natural gas sales less royalty and other revenue. Non-GAAP financial ratios Capital efficiency, presented on a $/boe basis is a non-GAAP ratio within the meaning of NI 52-112 as it has “capital expenditures”, a non-GAAP measure as, a component. This measure is not a standardized measure under IFRS and might not be comparable to similar financial measures presented by other companies. This measure should not be considered in isolation or construed as an alternative to its most directly comparable measure disclosed in the Financial Statements or other measures of financial performance calculated in accordance with IFRS. Capital efficiency represents the capital spent to add new or incremental production and is calculated by dividing such capital expenditures by the current rate of the new or incremental production, expressed as a dollar amount per flowing volume of a product ($/boe/d). The Company considers capital efficiency a key measure in evaluating its performance, as it provides management and investors with a means of analyzing the financial return on capital deployed. F&D costs are calculated by dividing: (i) capital expenditures, excluding green energy projects (a non-GAAP financial measure) for the applicable reserves category and period, by (ii) the net changes to reserves in such reserves category from the prior period from extensions & improved recovery, technical revisions, and economic factors, expressed in boe. FD&A costs are calculated by dividing: (i) capital expenditures and net acquisitions, excluding green energy acquisitions (a non-GAAP financial measure) for the applicable reserves category and period, by (ii) the net changes to reserves in such reserves category from the prior period from extensions and improved recovery, technical revisions, economic factors, acquisitions, and dispositions, expressed in boe. F&D costs and FD&A costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects, acquisitions net of dispositions (for FD&A only), and reserve additions. Operating netback per boe is a non-GAAP ratio within the meaning of NI 52-112 as it has “operating netback”, a non-GAAP financial measure as, a component. This measure is not a standardized measure under IFRS and might not be comparable to similar financial measures presented by other companies. Operating netback per boe is calculated as operating netback divided by total production for the period as measured by boe. See the heading “Non-GAAP and other financial measures” in the MD&A, available on SEDAR+ at www.sedarplus.ca and incorporated by reference into this presentation, for a detailed analysis, calculation and reconciliation of operating netback per boe. Free funds flow (deficiency) from operations is adjusted funds flow from operations less capital expenditures prior to property acquisitions. Management uses free funds flow as a key measure to analyze the Company’s ability to generate returns for investors and repay debt. The composition of Free funds flow (deficiency) from operations, as well as its comparison to prior periods, is disclosed within the MD&A. Capital management measures Adjusted funds flow from operations, free funds flow, net debt, and net debt to adjusted funds flow from operations are capital management measures that may not be comparable to similar financial measures presented by other companies. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Financial Statements or other measures of financial performance calculated in accordance with IFRS. See the headings “Non-GAAP and other financial measures” in the MD&A, available on SEDAR+ at www.sedarplus.ca and incorporated by reference into this presentation, for a detailed analysis, calculation and reconciliation of these capital management measures. The most directly comparable financial measure to each of these capital management measures disclosed in the Financial Statements is cash flow from operating activities. Non-GAAP and other financial measures