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kelt exploration Focused . Disciplined . Experienced . Corporate Presentation AUGUST 2026 TSX | KEL R & A
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2 Why Invest in Kelt ? Value Creation Kelt focuses on value creation for shareholders over the long-term. The Company emphasizes low- cost land accumulation in resource-style plays with the potential for high rates of return on capital invested and rapid growth of its drilling inventory portfolio. The Kelt management team has a track record of creating additional value through opportunistically timed monetizations: Sold Celtic Exploration Ltd. (primarily Montney and Duvernay assets) in February 2013 for: $3.2 billion Sold Kelt’s Inga Montney assets in August 2020 for: $510 million $100 million Sold Kelt’s Karr Montney assets in January 2017 for: Resource base includes: 359,000 acres of Montney rights Resource base includes: 93,000 acres of Charlie Lake rights Recycle ratio of: 1.7 x achieved since inception (~ 13 years), on a proved plus probable reserve basis. Kelt has a large and focused resource base in the Montney and Charlie Lake fairways. Management and the Board are aligned with all Kelt shareholders through their significant equity ownership in the Company. TSX | KEL
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3 Operating Divisions Grande Cache Wembley / Pipestone Oak / Flatrock Pouce Coupe / Progress ABB.C Calgary Edmonton • Prince Rupert • Kitimat Fort St. John • • Grande Prairie Oak / Flatrock > Montney liquids-rich gas Pouce Coupe / Progress > Montney light oil > Montney and Doig gas > Charlie Lake light oil Wembley / Pipestone > Montney light oil/condensate-rich gas Grande Cache > Cretaceous gas TSX | KEL
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4 Capital Structure The Company Stock Exchange Listing TSX Trading Symbol KEL Market Capitalization $2.0 billion ( @ $ 9.64 effective Aug/4/2026 ) 52-week Stock Trading Range $5.95 – $10.45 Common Shares 203.0 million LTI’s Options ( 5.2 MM ) & SBAs ( 2.5 MM ) 7.7 million ( 3.8% of basic shares ) Diluted Common Shares ( includes all LTI’s ) 210.7 million ( average exercise price of stock options is $ 5.50 / share ) Directors & Officers Ownership 18% ( 20% diluted ) TSX | KEL
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5 Insider Commitment [1] Insiders also purchased $14.7 million of the $90.0 million convertible debenture offering in May 2016. The Company redeemed the convertible debentures on October 3, 2020. [2] Insiders (excluding retired directors) total current holdings are 37.6 million shares or 18% of outstanding shares (does not include shares that may be received from exercising current rights under LTI plans). Equity Offering / Market Purchases Insider Purchases Date Shares (MM) Amount (MM) Price/Share $ 13.9 MM Equity Private Placement Feb-2013 3.7 $ 8.7 $ 2.32 $ 94.4 MM Equity Private Placement Apr-2013 5.7 $ 31.5 $ 5.55 $ 92.0 MM Equity Private Placement Aug-2013 0.5 $ 4.0 $ 8.00 $ 19.6 MM Flow-through Equity Private Placement Aug-2013 0.5 $ 4.9 $ 9.80 $ 101.1 MM Equity Private Placement Dec-2013 2.4 $ 19.6 $8.15 $ 33.6 MM Flow-through Equity Private Placement Mar-2014 1.1 $ 13.5 $ 12.75 $ 33.4 MM Flow-through Equity Private Placement Mar-2015 1.7 $ 14.7 $ 8.60 $ 90.0 MM Equity Prospectus Offering Jul-2015 0.4 $ 3.5 $ 8.85 $ 94.5 MM Flow-through Equity Private Placements 2016-2019 0.3 $ 1.8 $ 6.05 Open Market Purchases 2013-2026 15.5 $ 48.7 $ 3.14 TOTAL [2] 31.8 $ 150.9 $ 4.75 TSX | KEL
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6 Capital Expenditures – Three-Year Comparative [1] A&D – Acquisitions & Dispositions. See “Financial Advisories”. [2] 2025 includes $14.0 million for a 3-D Seismic Shoot that covered approximately 286 KM² (~70,400 acres or 110 sections) at Oak in British Columbia. ( $ Millions) 2024 2025 2026 Forecast 2026/25 Change Drilling & Completions 212.1 183.8 269.0 46% Infrastructure: Equipment, Facilities, Pipelines & Tangible Inventory 112.7 127.7 96.0 ( 25% ) Land, Seismic, Corporate Assets & Property Acquisitions, net of Dispositions [2] 8.3 16.8 10.0 ( 40% ) Capital Expenditures, net of A&D [1] 333.1 328.3 375.0 14% TSX | KEL
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7 Drilling & Completions Program [1] Excludes service wells (water disposal wells, water source wells, etc.). Drills 2024 Gross / Net Wells 2025 Gross / Net Wells 2026 Forecast Gross / Net Wells Alberta 29 26.3 29 23.8 34 32.5 British Columbia 5 5.0 4 4.0 4 4.0 Total 34 31.3 33 27.8 38 36.5 Completions 2024 Gross / Net Wells 2025 Gross / Net Wells 2026 Forecast Gross / Net Wells Alberta 26 23.3 29 24.6 37 34.7 British Columbia 8 8.0 2 2.0 6 6.0 Total 34 31.3 31 26.6 43 40.7 TSX | KEL
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8 Production – Three-Year Comparative [1] 2026 estimated NGLs production mix is as follows: Pentane ( C5+ ) 25% Butane ( C4 ) 24% Propane ( C3 ) 30% Ethane ( C2 ) 18% Sulphur ( S ) 3% Total NGLs 100% [2] BOE Conversions: → natural gas volumes are converted to oil equivalence on the basis of 6 Mcf = 1 BOE; and → sulphur volumes are converted to oil equivalence on the basis of 0.6 lt = 1 BOE and are included in NGLs. [3] Percent change is calculated from the mid-point of the forecasted production range. Oil & NGLs production in 2026 is expected to increase by 35% compared to 2025 and Gas production is expected to increase by 21%. 2024 2025 2026 Forecast Product Mix Product Mix Product Mix Oil ( bbls/d ) 8,623 26% 9,316 23% 12,300 – 12,900 25% NGLs ( bbls/d ) [1] 3,675 11% 5,545 14% 7,300 – 7,700 14% Gas ( Mcf/d ) 124,902 63% 153,214 63% 182,400 – 188,400 61% Combined ( BOE/d ) [2] 33,115 100% 40,397 100% 50,000 – 52,000 100% Annual Percent Change [3] 9% 22% 26% Per MM Shares ( BOE/d ) 169 203 248 - 257 TSX | KEL
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9 Raw Gas Processing Arrangements Division During 2024 During 2025 During 2026 During 2027 During 2028 During 2029 During 2030 Wembley / Pipestone 59.0 109.0 124.0 124.0 134.0 134.0 144.0 Pouce Coupe / Progress 83.0 108.0 108.0 118.0 118.0 118.0 118.0 Oak / Flatrock 45.0 65.0 90.0 90.0 105.0 120.0 120.0 TOTAL 187.0 282.0 322.0 332.0 357.0 372.0 382.0 Gas Plant Diversification Kelt has entered into various agreements that provide the Company with the ability to double its raw gas processing capacity as follows: NOTE: New Gas Processing Commitments (2026 – 2030): > CSV Albright Gas Plant → 50 MMcf/d in 2025 plus an additional 20 MMcf/d between 2028 and 2030; > ALA Pipestone # 2 Gas Plant Expansion → 15 MMcf/d included in 2026 (commenced operations in Dec/25); > NRM Gordondale West Gas Plant → up to 35 MMcf/d by 2027; and > NRM McMahon Gas Plant → up to 120 MMcf/d by 2029. TSX | KEL
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10 Summary of Reserves [1] Reserves are per the reports prepared by McDaniel & Associates Consultants Ltd. Reserve volumes include Company gross working interest share of remaining reserves, as determined in accordance with NI 51-101. [2] McDaniel does not include the volume of sulphur expected to be produced in the BOE reserve amounts, however, the net pres ent value of estimated future sulphur sales are included in the NPV amounts. [3] NPV (net present value). BT (before tax). $M (thousands). MBOE (thousands of barrels of oil equivalent). ( $M - NPV 10% BT ) Dec/31/2024 Dec/31/2025 Change Proved Developed Producing $ 882,521 $ 887,348 1% Proved $ 2,154,375 $ 1,961,806 ( 9% ) Proved plus Probable $ 3,471,756 $ 3,311,340 ( 5% ) ( MBOE ) Dec/31/2024 Dec/31/2025 Change Proved Developed Producing 78,862 83,482 6% Proved 266,312 265,084 0% Proved plus Probable 435,151 448,304 3% Oil & NGLs / Gas Mix 40% 60% 39% 61% TSX | KEL
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11 Net Asset Value [1] Reserves are per the reports prepared by McDaniel & Associates Consultants Ltd. Reserve volumes include Company gross working interest share of remaining reserves, as determined in accordance with NI 51-101. [2] Net present value of reserves is determined using a 10% discount rate, before tax. [3] The calculation of expected proceeds from the exercise of stock options and the diluted number of common shares outstanding only include stock options that are “in-the-money” based on the closing price of KEL of $7.67 at December 31, 2025. All outstanding RSUs and PSUs are included in diluted common shares outstanding. [4] Based on the Company’s net debt at December 31, 2025. [5] See Financial Advisories. Net Asset Value per Share December 31, 2025 $ M $/share Proved reserves [2] 1,961,806 9.35 Probable reserves [2] 1,349,533 6.43 Undeveloped land 118,094 0.56 Net debt [4] [5] ( 189,703 ) ( 0.90 ) Proceeds from exercise of stock options [3] 37,829 0.18 Net asset value [5] 3,277,559 15.62 Diluted shares outstanding (M) [3] 209,777 Forecasted Future Commodity Prices WTICrude Oil (USD/bbl) NYMEX HH Natural Gas (USD/MMBtu) Exchange Rate (CAD / USD) 2026 59.92 3.74 1.370 2027 65.10 3.78 1.351 2028 70.28 3.85 1.351 2029 71.93 3.93 1.351 2030 73.37 4.01 1.351 TSX | KEL
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12 Commodity Prices – Three-Year Comparative [1] WTI – West Texas Intermediate – light sweet crude oil (API 40˚) for settlement at Cushing, Oklahoma, priced in USD. [2] MSW – Mixed Sweet Blend – light sweet crude oil (API 40˚) for settlement at Edmonton, Alberta, priced in CAD. [3] AECO and Station 2 converted from GJ to MMBtu at a factor of 1.0546 GJ / MMBtu (1,000 Btu/scf gas). [4] See “Financial Advisories”. ( $CAD, unless otherwise specified ) 2024 2025 2026 Forecast WTI Crude Oil ( $/bbl ) [1] US $ 76.56 $104.89 US $ 65.43 $ 91.45 US $ 79.50 $ 110.11 MSW Crude Oil ( $/bbl ) [2] US $ 72.04 $ 98.70 US $ 61.89 $ 86.51 US $ 77.98 $ 108.00 NYMEX Henry Hub Natural Gas ( $/MMBtu ) US $ 2.25 $ 3.08 US $ 3.53 $ 4.95 US $ 3.50 $ 4.85 DAWN Gas Daily Index ($/MMBtu) US $ 1.97 $ 2.70 US $ 3.24 $ 4.53 US $ 3.20 $ 4.42 CHICAGO [ACE] Gas Daily Index ($/MMBtu) US $ 2.06 $ 2.82 US $ 3.25 $ 4.54 US $ 3.30 $ 4.57 SUMAS Gas Daily Index ($/MMBtu) US $ 2.00 $ 2.74 US $ 1.66 $ 2.33 US $ 1.90 $ 2.63 MARCELLUS [T Z4 L300] Daily Index ($/MMBtu) US $ 1.64 $ 2.25 US $ 2.77 $ 3.88 US $ 2.90 $ 4.02 AECO [NIT 5A] Gas Daily Index ($/MMBtu) [3] US $ 1.07 $ 1.46 US $ 1.19 $ 1.68 US $ 1.34 $ 1.85 STATION 2 Gas Daily Index ($/MMBtu) [3] US $ 0.87 $ 1.19 US $ 0.72 $ 1.00 US $ 1.19 $ 1.65 Exchange Rate ( CAD/USD ) US $ 0.730 $ 1.370 US $ 0.716 $ 1.398 US $ 0.722 $ 1.385 Net realized Oil price ( $/bbl ) $ 94.46 $ 83.29 $ 106.28 Net realized NGLs price ( $/bbl ) $ 47.56 $ 35.94 $ 49.91 Net realized Gas price ( $/Mcf ) $ 1.97 $ 2.50 $ 2.45 Net realized combined price ( $/BOE ) $ 37.31 $ 33.63 $ 41.89 TSX | KEL
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13 Commodity Prices – 2026 Forecast [1] WTI – West Texas Intermediate – light sweet crude oil (API 40˚) for settlement at Cushing, Oklahoma, priced in USD. [2] MSW – Mixed Sweet Blend – light sweet crude oil (API 40˚) for settlement at Edmonton, Alberta, priced in CAD. [3] AECO and Station 2 converted from GJ to MMBtu at a factor of 1.0546 GJ / MMBtu (1,000 Btu/scf gas). [4] See “Financial Advisories”. ( $ CAD, unless otherwise specified ) Jan-Jun 2026 Actual Jul-Dec 2026 Estimate 2026 Forecast WTI Crude Oil ( USD $/bbl ) [1] US $ 82.57 US $ 76.49 US $ 79.50 MSW Crude Oil ( $/bbl ) [2] $ 113.00 $ 103.09 $ 108.00 NYMEX Henry Hub Natural Gas ( USD $/MMBtu ) US $ 3.91 US $ 3.10 US $ 3.50 DAWN Gas Daily Index (USD $/MMBtu) US $ 3.49 US $ 2.91 US $ 3.20 CHICAGO [ACE] Gas Daily Index (USD $/MMBtu) US $ 3.94 US $ 2.67 US $ 3.30 SUMAS Gas Daily Index (USD $/MMBtu) US $ 1.41 US $ 2.39 US $ 1.90 MARCELLUS [T Z4 L300] Daily Index (USD $/MMBtu) US $ 3.54 US $ 2.28 US $ 2.90 AECO [NIT 5A] Gas Daily Index ($/MMBtu) [3] $ 1.82 $ 1.88 $ 1.85 STATION 2 Gas Daily Index ($/MMBtu) [3] $ 1.63 $ 1.67 $ 1.65 Exchange Rate ( CAD/USD ) $ 1.378 $ 1.392 $ 1.385 Net realized Oil price ( $/bbl ) $ 113.33 $ 100.53 $ 106.28 Net realized NGLs price ( $/bbl ) $ 50.51 $ 49.36 $ 49.91 Net realized Gas price ( $/Mcf ) $ 2.54 $ 2.37 $ 2.45 Net realized combined price ( $/BOE ) $ 42.92 $ 41.42 $ 41.89 TSX | KEL
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14 Netbacks – Three-Year Comparative ( $ / BOE ) 2024 2025 2025 / 24 change 2026 Forecast 2026 / 25 change Net realized price 37.31 33.63 ( 10% ) 41.89 25% Realized hedging gain ( loss ) 0.35 1.88 437% ( 0.43 ) ( 123% ) Royalties ( % of net realized price ) ( 12.1% ) ( 9.3% ) ( 23% ) ( 11.7% ) 26% Transportation expense ( 3.52 ) ( 3.43 ) ( 3% ) ( 3.26 ) ( 5% ) Production expense ( 10.01 ) ( 9.52 ) ( 5% ) ( 10.02 ) 5% Operating netback [1] 19.61 19.43 ( 1% ) 23.29 20% G&A expense ( 1.01 ) ( 0.92 ) ( 9% ) ( 0.95 ) 3% Interest expense ( 0.30 ) ( 0.76 ) 153% ( 0.64 ) ( 16% ) Other income ( expense ) 0.03 ( 0.01 ) — 0.03 — Adjusted funds from operations [1] 18.33 17.74 ( 3% ) 21.73 22% Settlement of ARO ( 0.42 ) ( 0.23 ) ( 45% ) ( 0.40 ) 74% Funds from operations [1] 17.91 17.51 ( 2% ) 21.33 22% [1] See “Financial Advisories”. TSX | KEL
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15 Financial Summary – Three-Year Comparative [1] See “Financial Advisories”. [2] Net debt includes working capital except for derivative financial instruments (mark to market), decommissioning obligations and lease liabilities. ( $ MM, unless otherwise specified ) 2024 2025 2026 Forecast 2026/25 change P&NG sales 468.4 513.1 804.7 57% Adjusted funds from operations [1] 222.0 261.5 410.0 57% AFFO per share – diluted ( $/share ) [1] 1.11 1.29 1.99 54% Capital expenditures, net of A&D [1] 333.1 328.3 375.0 14% Net debt, at year-end [1,2] 124.9 189.7 153.0 ( 19% ) Net debt / AFFO ratio ( times ) [1,2] 0.6 x 0.7 x 0.4 x TSX | KEL
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16 Land Fairway Land Holdings Developed + Undeveloped Gross Acres Net Acres Net Sections BC Montney 196,795 193,609 302 AB Montney 173,128 165,493 259 Total Montney 369,923 359,102 561 AB Charlie Lake 136,880 93,350 146 Total Company 802,281 601,706 940 Kelt Lands AlbertaBritish Columbia Oak Flatrock Progress Wembley / Pipestone Pouce Coupe Grande Prairie 94-A-1094-A-11 94-A-9 Fort St. John R20 R18 R16 R14W6 TSX Ι KEL Division Company Oak / Flatrock Kelt Exploration (LNG) Ltd. ( a wholly-owned subsidiary ) Pouce Coupe / Progress Kelt Exploration Ltd. ( parent company ) Wembley / Pipestone Kelt Exploration Ltd. ( parent company )
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17 Montney Framework Oak / Flatrock Pouce Coupe Progress La Glace Pipestone / Wembley Area Primary Montney Target Oak Upper and D4 Pouce Coupe West Lower, D1 and D2 Progress D1 La Glace D3 Pipestone / Wembley D3 and D4 Average Porosity (%) 5.7 4.9 6.3 4.8 4.6 Gross Thickness (m) 95 132 57 51 107 Net Pay > 3% (m) 90 87 52 42 81 Initial Pressure (MPa) * 15 - 18 27 - 30 19 - 20 22 - 23 20 - 25 Pressure Gradient (kPa/m) 10 - 12 11 - 13 10 10 10 - 11 * Reservoir pressures vary due to the range of target interval depths across the breadth of each area's land base. Proven Productive Montney Horizons Kelt Future Exploratory Horizons within Core Areas TSX Ι KEL
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18 Operating Divisions – 2025 Summary of Reserves and Production [1] Reserves and Reserves Value (NPV calculated using a 10% discount rate, before tax) are per the report effective December 31, 2025, prepared by McDaniel & Associates Consultants Ltd. [2] Reserve volumes include Company gross working interest share of remaining reserves, as determined in accordance with NI 51 -101. [3] Netback – see Financial Advisories. 2025 Production 2025 Netback [3] Proved Reserves Value [1] P+P Reserves Value [1] P+P Reserves [1] [2] Division BOE/d Oil/NGLs $/BOE $ MM $ MM MBOE Oil/NGLs Pouce Coupe/Progress 17,758 26% $ 15.47 633 937 110,720 25% Wembley/Pipestone 14,885 54% $ 25.30 1,019 1,804 229,806 51% Oak/Flatrock 6,378 31% $ 8.81 307 558 102,485 28% Other (incl. Grande Cache) 1,376 20% $ 1.20 3 12 5,293 14% Total Company 40,397 37% $ 19.44 1,962 3,311 448,304 39% TSX | KEL
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19 Well Costs & Drilling Inventory [1] Averages for each category were determined based on actual results for a group of recent wells drilled and completed in e ach area. Average well costs are for drill, case & complete. Equipment & tie-in costs for wells on development pads, on average, would be an additional $600,000 per well. Estimated liquids content is based on actual volumes produced up to December 31, 2025 and estimated reserves for the remaining life of each well included in the group of wells. [2] Wembley Montney drilling inventory includes 662 wells in the D3/D4 zones and 192 wells in the D1 zone. [3] Charlie Lake metrics are for the Spirit River and Progress area only. Kelt has additional Charlie Lake drilling inventory at Wembley and Pouce Coupe North that has not been included in the table above. [4] See “Disclaimer” for discussion relating to “Reserves” and “Future Drilling Locations”. Wembley Montney Oak Montney Progress / Spirit River Charlie Lake [3] Well Cost – Drill, Case & Complete ($MM) [1] $ 7.4 $ 7.3 $ 4.8 Total Vertical Depth (metres) [1] 2,200 1,500 1,600 Lateral Length Completed (metres) [1] 3,000 4,600 3,000 Completions – Sand Tonnage (tonnes/metre) [1] 2.75 1.75 0.60 Completions – Water Intensity (cubic metres/ton) [1] 4.0 3.5 6.1 Future Drilling Location Inventory (un-risked) [4] 854 [2] 576 46 Future Drilling Locations included in 2P Reserves [4] 233 91 26 Percent of Inventory booked in 2P Reserves 27% 16% 57% Production Expense ($/BOE) [1] $ 9.40 $ 8.10 $ 8.45 Transportation Expense ($/BOE) [1] $ 2.40 $ 2.50 $ 3.80 Estimated Liquids (Oil & NGLs) content over the life of the well [1] 50% 27% 55% TSX | KEL
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20 British Columbia Montney - Oak / Flatrock Division 2025 Montney Drilling Program 5-32 Pad 4 wells ( 2 completed & 2 DUCs in 2025 ) 2026 Montney Drilling Program 5-32 Pad 4 wells ( 6 Completions ) Montney Land Holdings & Drilling Inventory Gross 191,745 acres ( 300 sections ) Net 190,473 acres ( 298 sections ) Future drilling locations (un-risked ) 576 wells Drilling locations included in P+P FDC 91 ( 16% booked ) > Kelt processes gas from Oak at the McMahon Gas Plant. > Kelt sells gas produced from Oak to various pricing point hubs including Station 2 (BC), ACE (Chicago), TZ4 L300 (Marcellus/Pennsylvania) and Sumas (Washington). 16” NRM Main Line 12.75” NRM Main Line NRM Main Lines continue to: NRM McMahon Gas Plant 5-32 Kelt Lands 2026 Locations Existing Wells Pipelines Kelt Facility (100%) TSX | KEL Kelt 6-35
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21 Alberta Montney Lands Alberta − Montney Land Holdings Gross 173,128 acres ( 271 sections ) Net 165,493 acres ( 259 sections ) Pouce Coupe West > High deliverability dry gas wells. > Kelt has an inventory of approximately 20 to 25 wells to be drilled here. Pouce Coupe / Progress > Oil-prone area with associated gas production. Wembley / Pipestone / La Glace > Delineation of this large Montney land block now almost complete. > Extensive infrastructure currently in place. > Most active drilling area for the Company. Pouce Coupe Progress La Glace Wembley / Pipestone Pouce Coupe West Pouce Coupe North Kelt Lands 62 sections 190 sections TSX Ι KEL
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22 Pouce Coupe / Progress Division – Montney 2025 Montney Drilling Program Pouce Coupe West: 16-13 Pad 3 wells ( 1 DUC in 2025 ) Pouce Coupe North: 9-12 Pad 2 wells 2026 Drilling Program Pouce Coupe West: 16-13 Pad 1 Montney well ( 2 completions ) Pouce Coupe North: 9-12 Pad 3 Montney wells 1 Halfway well NRM Fourth Creek NRM Gordondale East Progress (20% WI) Progress (oil-prone) NRM Gordondale West Pouce Coupe (oil-prone) Pouce Coupe West (gas-prone) Kelt Lands 2026 Locations Pipelines Gas Plant Pouce Coupe North 16-13 9-12 TSX Ι KEL
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23 Pouce Coupe / Progress Division – Charlie Lake Alberta (includes Wembley) − Charlie Lake Land Holdings Gross 136,880 acres ( 214 sections ) Net 93,350 acres ( 146 sections ) Spirit River/Progress – Charlie Lake Inventory Future drilling locations (un-risked ) 46 wells [1] Drilling locations included in P+P FDC 26 ( 57% booked ) 2025 Charlie Lake Drilling Program Spirit River 2 wells ( 3-14 pad ) Progress 4 well ( 10-7 pad @ 50% WI ) Pouce Coupe North 1 well ( 10-32 pad; completion only ) Wembley/Pipestone 2 wells ( 16-26 pad @ 58% WI ) [1] Drilling inventory is for locations at Spirit River and Progress only; and does not include inventory for potential Charlie Lake wells at Pouce Coupe North nor at Wembley/Pipestone. Pouce Coupe North Spirit River Progress 3-14 Kelt Lands 2026 Locations Existing Wells Pipelines Gas Plant NRM Gordondale East NRM Fourth Creek NRM Gordondale West Progress (20% WI) 1-11 16-24 10-32 TSX Ι KEL 2026 Charlie Lake Drilling Program Spirit River 2 wells ( 3-14 pad ) Progress 2 wells ( 16-24 pad @ 75% WI ) Progress 2 wells ( 1-11 pad @ 50% WI ) Pouce Coupe North 2 wells ( 10-32 pad )
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24 Wembley / Pipestone Division – Montney 2026 Montney Drilling Program 11-34 Pad 3 wells ( 4 completions ) 6-9 Pad 4 wells 16-26 Pad 4 wells 7-8 Pad 5 wells 14-26 Pad 3 wells 5-26 Pad 2 wells (La Glace - Montney D2 Turbidite ) 2025 Montney Drilling Program 14-2 Pad 3 wells ( completions only → 2024 DUCs ) 9-17 Pad 4 wells ( 5 tie-ins; includes a previous year’s well ) 6-9 Pad 5 wells 16-8 Pad 3 wells 11-34 Pad 1 well ( 2025 DUC ) Montney Land Holdings & Drilling Inventory Gross 124,808 acres ( 195 sections ) Net 121,659 acres ( 190 sections ) Future drilling locations (un-risked) 854 wells Drilling locations included in P+P FDC 233 ( 27% booked ) 7-8 6-9 11-34 16-26 ALA Pipestone I ALA Pipestone II CSV Albright OVV Sexsmith OVV Wembley KEY Pipestone Kelt Lands 2026 Locations Existing Wells Gas Plant Kelt Facility (100%) 5-26 14-26 TSX Ι KEL
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25 OVV Sexsmith OVV Wembley KEY Pipestone CSV Albright Kelt Lands Pipelines Gas Plant Kelt Facility (100%) Wembley / Pipestone Division – Infrastructure > Firm service agreements in place for gas processing at the following Midstream Facilities: > ALA Pipestone I/II Deep-Cut Gas Plant; > KEY Pipestone Gas Plant; and > CSV Albright Sulphur Recovery Gas Plant. Infrastructure > Ownership in extensive pipeline infrastructure and minor interests in the Sexsmith and Wembley Gas Plants. > In addition, Kelt has its own water disposal facilities capable of water injection at each of its main Facilities. 100% Interest in four Oil Battery and Gas Compression Facilities. Kelt 1-14 Kelt 14-2 Kelt 14-29 Kelt 11-31 ALA Pipestone I ALA Pipestone II Kelt Lands 2026 Locations Existing Wells Pipelines Gas Plant Kelt Facility (100%) TSX Ι KEL
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26 Looking Forward Future Considerations The Company has numerous potential future drilling opportunities on its existing lands that will provide for continued growth in the years ahead. The Company has amassed a vast Montney and Charlie Lake acreage position that will provide years of development drilling opportunity. The Company continues to maintain a strong financial position that will provide it with flexibility during volatile commodity markets. The Company may divest certain assets in order to monetize (bring forward) net present value and to fund continued growth in the future. TSX | KEL
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27 Kelt’s Leadership
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28 Neil G. Sinclair [ 4, 8, 10 ] Director, Independent Common shares 2,744,252 Stock options 74,000 RSUs 30,788 2025 Director fees $ 16,438 Corporate Governance - Board of Directors David J. Wilson [ 9 ] President & Chief Executive Officer Common shares 28,230,742 Stock options 647,500 RSUs 69,601 PSUs 154,803 Janet E. Vellutini [ 3, 6, 7 ] Director, Independent Common shares 93,566 Stock options 67,334 RSUs 30,788 2025 Director fees $ 16,438 [1] Chair, Audit Committee. [2] Chair, Reserves Committee. [3] Chair, Compensation and Corporate Governance Committee. [4] Chair, Health, Safety, Environment and Sustainability Committee. [5] Chair, Nominating Committee. [6] Member, Audit Committee. [7] Member, Reserves Committee. [8] Member, Compensation and Corporate Governance Committee. [9] Member, Health, Safety, Environment and Sustainability Committee. [10] Member, Nominating Committee. William C. Guinan [ 5, 8, 9 ] Board Chair, Independent Common shares 1,154,459 Stock options 24,000 RSUs 30,788 2025 Director fees $ 16,438 Jennifer J. Haskey [ 2, 6, 10 ] Director, Independent Common shares 5,400 Stock options 45,000 RSUs 33,788 2025 Director fees $ 16,438 Ray Kwan [ 1, 7 ] Director, Independent Common shares 105,755 Stock options Nil RSUs 28,388 2025 Director fees $ 11,387 TSX | KEL
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29 Leadership - Officers David J. Wilson President & Chief Executive Officer Common shares 28,230,742 Stock options 647,500 RSUs 69,601 PSUs 154,803 Sadiq H. Lalani Vice President & Chief Financial Officer Common shares 1,984,833 Stock options 317,000 RSUs 32,455 PSUs 70,365 Douglas J. Errico Senior Vice President, Land & Corporate Development Common shares 541,181 Stock options 317,000 RSUs 31,407 PSUs 67,220 Alan G. Franks Vice President, Production Common shares 409,964 Stock options 130,500 RSUs 26,683 PSUs 57,550 Bruce D. Gigg Vice President, Engineering Common shares 233,996 Stock options 270,000 RSUs 26,683 PSUs 57,550 David A. Gillis Vice President, Finance Common shares 108,155 Stock options 270,000 RSUs 26,683 PSUs 57,550 Douglas O. MacArthur Vice President, Operations Common shares 1,016,299 Stock options 235,000 RSUs 26,683 PSUs 57,550 Patrick W. G. Miles Vice President, Exploration Common shares 911,855 Stock options 28,334 RSUs 26,683 PSUs 57,550 Louise K. Lee Corporate Secretary Common shares 30,028 Stock options 35,000 RSUs 12,354 TSX | KEL
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30 Appendix
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31 Gas Market Risk Management Station 2 Sumas AECO Empress Emerson Dawn Chicago Malin Socal Permian Henry Hub (NYMEX) Opal Waddington Marcellus ❖ Kelt has transferred a portion of its physical AECO hub exposure to other hubs via basis/percentage swaps. ❖ Kelt has transferred a portion of its AECO hub exposure to the AESO power market via heat factor swaps. Gas Market Diversification Kelt has taken a diversified approach to selling its natural gas in order to reduce exposure to a single market risk. AECO ( 60% ) Dawn ( 14% ) LNG JKM - Asia ( 3% ) LNG TTF - Europe ( 3% ) Chicago ( 2% ) AESO ( 4% ) Marcellus ( 1% ) Sumas ( 1% ) ATP ( 1% ) Station 2 ( 11% ) Estimated 2026 percentage of average gas production at each respective price hub: TSX | KEL
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32 Commodity Price Risk Management ( 1 of 2 ) Commodity Index Type Remaining Term Quantity Contract Price Natural Gas AECO/NYMEX Put/Call Collar Financial Jul - Dec/26 21,000 GJ/d & 20,000 MMBtu/d AECO Put Option ( floor ) @ CAD$2.80/GJ and NYMEX Call Option ( ceiling ) @ USD$5.50/MMBtu [ equivalent to CAD $2.95/MMBtu X CAD $7.66/MMBtu at a CAD/USD exchange rate of 1.3920 ] Natural Gas JKM LNG ( Asia ) Physical Jul - Dec/26 5,000 MMBtu/d Floating Japan/Korea Marker LNG Price ( USD/MMBtu ) multiplied by 22.0% [ contract satisfied by physical delivery of gas at NGTL -NIT ] Natural Gas TTF Gas ( Europe ) Physical Jul - Dec/26 5,000 MMBtu/d Floating Dutch TTF Gas Price ( USD/MMBtu ) multiplied by 22.0% [ contract satisfied by physical delivery of gas at NGTL -NIT ] Natural Gas AESO Power Fixed Heat Factor Physical Jul - Dec/26 7,349 GJ/d Floating AESO Power Pool Price ( CAD/MWh ) divided by the Fixed Heat Rate of 16.752 GJ/MWh [ contract satisfied by physical delivery of gas at NGTL -NIT ] Power/ Electricity AESO Financial Jul - Dec/26 48 MW/d CAD $47.75/MWh [ fixed price purchase contract to protect against rising power costs included in production expenses ] TSX | KEL
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33 Commodity Price Risk Management ( 2 of 2 ) Commodity Index Type Remaining Term Quantity Contract Price Crude Oil WTI Financial Jul/26 – Sep/26 3,000 bbls/d CAD $90.83/bbl [ equivalent to USD $65.25/bbl at a CAD/USD exchange rate of 1.3920 ] Crude Oil MSW Financial Jul/26 – Sep/26 1,500 bbls/d MSW-WTI Basis Differential ( USD $1.95/bbl ) [ equivalent to CAD $2.71/bbl at a CAD/USD exchange rate of 1.3920 ] Crude Oil WTI Financial Oct/26 – Dec/26 3,000 bbls/d CAD $90.50/bbl [ equivalent to USD $65.01/bbl at a CAD/USD exchange rate of 1.3920 ] Propane OPIS Conway Financial Jul/26 - Mar/27 800 bbls/d Floating WTI Crude Oil Price ( USD/bbl ) multiplied by 50.5% Currency CAD/USD Fixed Rate Financial Jul/26 – Dec/26 USD $2.0 MM /month CAD $1.4025 / USD ( ~ USD $0.7130 / CAD ) [ extendable to 2027 with a knock-out provision on the extension if CAD trades at or below 1.3250 prior to December 31, 2026 ] Currency CAD/USD Fixed Rate Financial Jul/26 – Dec/26 USD $5.0 MM /month CAD $1.3972 / USD ( ~ USD $0.7157 / CAD ) NOTE: Kelt has provided financial institution counter-parties with an option to put the Company into the following contracts: [1] A fixed price WTI oil swap to sell 500 bbls/d for Jan-Jun 2027 (H1-27) at CAD $85.00/bbl exercisable on December 31, 2026. Option premium enhanced the fixed price on a swap from Jul-Dec 2026 (H2-26). [2] A fixed rate currency swap to sell USD $2.0 MM/month for Jan-Dec 2027 (Cal-27) at 1.4025 exercisable on December 31, 2026. Option premium enhanced the fixed rate on a swap from Jan-Dec 2026 (Cal-26). If CAD trades at or below 1.3250 prior to December 31, 2026, this option terminates. TSX | KEL
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34 July – December 2026 AFFO Forecast Jul-Dec 2026 Forecast Kelt Oil/NGLs Price Plus 10% Kelt Gas Price Plus 10% Kelt Oil Price (CAD/bbl) 100.53 110.58 +10% 100.53 — Kelt NGLs Price (CAD/bbl) 49.36 54.30 +10% 49.36 — Kelt Gas Price (CAD/Mcf) 2.37 2.37 — 2.61 +10% AFFO – 6 Months ( $MM ) [1] [2] 216.6 234.8 223.3 AFFO Change ( $MM / % ) + 18.2 + 8.4% + 6.7 + 3.1% [1] See “Financial Advisories” [2] AFFO: Adjusted Funds from Operations TSX | KEL AFFO Sensitivities to Commodity Price Fluctuations: Impact to 2026 Forecast: AFFO – full year ( $MM ) [1] [2] 410.0 428.2 416.7 AFFO Change ( $MM / % ) + 18.2 + 4.4% + 6.7 + 1.6%
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35 2023 to 2025 - Three Year Average Recycle Ratios [1] Reserves are per the report prepared by McDaniel & Associates Consultants Ltd. Reserve volumes include Company gross working interest share of remaining reserves, as determined in accordance with NI 51-101. [2] FDA&D (Finding, development, acquisition & disposition). FDC (Future development capital). PDP (Proved developed producing). P+P (Proved plus probable). [3] See Financial Advisories. ( $ M, unless otherwise specified ) PDP Reserves Proved Reserves P+P Reserves Capital expenditures, net of dispositions Change in FDC costs required to develop reserves 944,098 6,850 944,098 718,139 944,098 1,070,702 Total capital costs 950,950 1,662,239 2,014,802 Reserve additions, net of dispositions ( MBOE ) 60,363 110,954 145,446 FDA&D cost ( $/BOE ) 15.75 14.98 13.85 Operating netback [3] ( $/BOE ) 21.34 21.34 21.34 Recycle ratio 1.4 x 1.4 x 1.5 x TSX | KEL
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36 Reserves – Future Development Capital [1] Reserves are per the report prepared by McDaniel & Associates Consultants Ltd. Reserve volumes include Company gross working interest share of remaining reserves, as determined in accordance with NI 51-101. [2] Other expenditures includes drill and completion costs for wells in other formations and completion expenditures for either Montney or Charlie Lake wells that were DUCs at December 31, 2025. [3] “FDC” = Future Development Capital. “DUCs” = Drilled but Un-completed Wells. December 31, 2025 Proved Reserves [1] P+P Reserves [1] FDC ( $ MM ) Net Wells FDC ( $ MM ) Net Wells Alberta Montney wells 1,276 174 2,120 276 B.C. Montney wells 446 61 674 91 Alberta Charlie Lake wells 146 28 251 47 Other expenditures [2] 60 7 70 8 TOTAL FDC EXPENDITURES [3] 1,928 270 3,115 422 TSX | KEL
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37 ROACE – Three Year Comparative [1] See “Financial Advisories”. [2] “ROACE” – Return on average capital employed. [3] “EBIT” – Earnings before interest and taxes. ( $ millions ) 2023 2024 2025 3-year Average Net Debt [1] 11.4 68.9 157.3 79.2 Lease Obligations 1.3 1.8 1.5 1.5 Shareholders’ Equity 952.5 1,033.3 1,101.3 1,029.1 Average Capital Employed 965.2 1,104.0 1,260.2 1,109.8 Adjusted EBIT [3] 115.8 66.8 95.3 92.6 ROACE [2] 12.0% 6.1% 7.6% 8.5% Return on average capital employed (ROACE) measures the efficiency of Kelt’s utilization of the capital that it employs. In this calculation, ROACE is defined as earnings for the period adjusted for interest expense and taxes as a percentage of the average capital employed for the period. TSX | KEL
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38 Disclosures
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39 Abbreviations and Definitions A&D acquisitions & dispositions ACE the Chicago natural gas hub pricing point identified as Alliance Chicago Echange AECO Alberta Energy Company “C” Meter Station of the Nova Gas Pipeline System AESO Alberta Electric System Operator AFFO adjusted funds from operations ALA AltaGas Ltd. ARO asset retirement obligation bbls/d barrels per day BOE/d barrels of oil equivalent per day CSV CSV Midstream Solutions Corp. DUC a drilled but un-completed well GAAP generally accepted accounting principles gas-prone the quality of a source rock that makes it more likely to generate gas than oil GHG greenhouse gas emissions GJ gigajoules KEY Keyera Corp. LNG liquefied natural gas LT long tonnes McDaniel McDaniel & Associates Consultants Ltd, an independent qualified reserve evaluator Mcf/d thousand cubic feet per day M thousand MM million MSW medium sweet blend NGTL Nova Gas Transmission Limited NIT Nova Inventory Transfer NRM NorthRiver Midstream Inc. NYMEX HH natural gas delivery at Henry Hub traded on the New York Mercantile Exchange oil-prone the quality of a source rock that makes it more likely to generate oil than gas OVV Ovintiv Inc. P&NG petroleum and natural gas P+P proved plus probable reserves PDP proved developed producing reserves ROACE return on average capital employed SBA stock based award sfc well surface location TAR facility maintenance turnaround operations TZ4 L300 the Marcellus natural gas hub pricing point identified as Tennessee Zone 4 Leg 300 WTI West Texas Intermediate TSX Ι KEL
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40 Disclaimer Forward-Looking Statements Certain statements included in this corporate presentation (the “Presentation”) constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward looking statements or information typically contain statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project“, “goal”, “objective”, “assume”, “forecast” or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this Presentation include, but are not limited to, statements or information with respect to: Kelt Exploration Ltd.'s (“Kelt” or the “Company”) business strategy and objectives; statements with respect to the performance characteristics of Kelt’s oil and natural gas properties and wells; potential future drilling locations; development plans, exploration plans, delineation drilling, in-fill drilling, optimization plans and effect on costs and production; the Company’s focus for 2025 and 2026, including capital expenditures, budgeted drilling and completion costs per well, drilling program, anticipated net debt; anticipated production and production mix; estimated recoverable resources; expansion of infrastructure; timing of drilling and completions; ability to obtain necessary permits and licenses; plans to investigate or participate in infrastructure projects; the timing and costs to construct processing facilities and sales pipelines; forecasted pricing; actual and estimated internal rates of return, which include assumptions respecting production and other costs, pricing, well depths, royalty rates, taxes and government regulations; financial and operating results; economic metrics including capital, IRR, net present values, EUR, netbacks, and production rates; that the estimated future production and operating income for development wells will be sufficient to payback the drill and complete capital costs incurred for each respective well; the expectation that the Company’s gas market diversification will limit exposure to single market risk. In addition, the statements contained herein relating to “reserves” and “resources” are by their nature forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves or resources described exist in the quantities predicted or estimated and that the reserves or resources can be profitably produced in the future. Actual reserves or resources may be greater than or less than the estimates provided herein. TSX Ι KEL
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41 Disclaimer Future Oriented Financial Information This Presentation contains Future Oriented Financial Information (“FOFI”) within the meaning of applicable securities laws. The FOFI has been prepared by Kelt’s management to provide an outlook of the Company's activities and results. The FOFI has been prepared based on a number of assumptions including the assumptions discussed under the heading “Forward Looking Statements” and assumptions with respect to the costs and expenditures to be incurred by the Company, capital equipment and operating costs, foreign exchange rates, taxation rates for the Company, general and administrative expenses and the prices to be paid for the Company's production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results will likely vary from the amounts set forth in the analysis presented in this Presentation, and such variation may be material. The Company and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. However, because this information is highly subjective and subject to numerous risks including the risks discussed under the heading “Forward Looking Statements”, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Kelt undertakes no obligation to update such FOFI and forward-looking statements and information. Assumptions Forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. 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 because the Company can give no assurance that such expectations will prove to be correct. References herein to the IP30 and IP365 production rates are useful in confirming the presence of hydrocarbons, however the production rates are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the assets for which such rates are provided. TSX Ι KEL
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42 Disclaimer In addition to other factors and assumptions which may be identified in this Presentation, assumptions have been made regarding, among other things: commodity prices; the accuracy of geological and geophysical data and its interpretations of that data; estimated decline rates; the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals including First Nations consultation; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the Company to operate in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; that the Company will have sufficient cash flow, debt or equity or other financial resources to fund its capital and operating expenditures as needed; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; that the estimates of the Company’s reserve volumes and assumptions related thereto are accurate in all material respects; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Risks and Uncertainties Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which 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 which may cause actual results to differ materially from the forward looking statements or information include, among other things: the ability of management to execute its business plan; general economic and business conditions; the risk of instability affecting the jurisdictions in which the Company operates; the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand; the possibility that government policies or laws may change or governmental or First Nation approvals may be delayed or withheld; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserves estimates and reserves life; the ability of the Company to add production and reserves through acquisition, development and exploration activities; the Company’s ability to enter into or renew leases; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to production (including decline rates), costs and expenses; fluctuations in oil and gas prices, foreign currency exchange rates and interest rates; risks inherent in the Company's marketing operations, including credit risk; uncertainty in amounts and timing of royalty payments; health, safety and environmental risks; risks associated with potential future lawsuits and regulatory actions against the Company; uncertainties as to the availability and cost of financing; changes in income tax rates; changes in incentive programs related to the oil and gas industry; and financial risks affecting the value of the Company’s investments. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. TSX Ι KEL
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43 Disclaimer No Obligation to Update The forward-looking statements or information contained in this Presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this Presentation are expressly qualified by this cautionary statement. Oil and Gas Advisories Barrel of Oil Equivalent Presentation This Presentation contains various references to the abbreviation BOE which means barrels of oil equivalent. Where amounts are expressed on a BOE basis, natural gas volumes have been converted to oil equivalence at six thousand cubic feet per barrel and sulphur volumes have been converted to oil equivalence at 0.6 long tons per barrel. The term BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead and is significantly different than the value ratio based on the current price of crude oil and natural gas. This conversion factor is an industry accepted norm and is not based on current prices. Such abbreviation may be misleading, particularly if used in isolation. References to “oil” in this Presentation include crude oil and field condensate. References to “natural gas liquids” or “NGLs” include pentane plus, butane, propane, ethane and sulphur. References to “liquids” includes crude oil, field condensate and NGLs. References to “gas” in this discussion include natural gas. Type Well Production and Economics This Presentation contains references to type well, or “type curve”, production and economics, which are derived, at least in part, from available information respecting the well economics of other companies and, as such, there is no guarantee that Kelt will achieve the stated or similar results, capital costs and return costs per well. Any references to peak rates, test rates or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or ultimate recovery. In addition, such rates or declines may also include recovered fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company. TSX Ι KEL
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44 Disclaimer Reserves Unless otherwise specified, reserve estimates disclosed in this Presentation were prepared by McDaniel & Associates Consultants Ltd (“McDaniel”) 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 (“COGE Handbook”) and using McDaniel’s forecast prices. There is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward looking statements. EUR is not indicative of reserves. Estimates of the net present value of the future net revenue from Kelt’s reserves do not represent the fair market value of Kelt’s reserves. Reserves estimates contained herein have been made assuming that funding is likely to be available to Kelt for the development of the applicable property. Future Drilling Locations Unless otherwise specified, the information in this Presentation pertaining to future drilling locations or drilling inventories is based solely on internal estimates made by management and such locations have not been reflected in any independent reserve or resource evaluations prepared pursuant to NI 51‐101. Similarly, unless otherwise specified, the information in this Presentation pertaining to targeted reserve volumes from future drilling is intended to indicate that in making its internal drilling decisions, the Company seeks to target drilling locations that, based on previous drilling results and its own internal assessments, it believes will on average ultimately generate the indicated volumes. This Presentation discloses drilling locations which are unbooked locations and are internal estimates based on Kelt'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 and have been identified by management as an estimation of multi‐year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Kelt 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 we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Estimated Ultimate Recovery Estimated Ultimate Recovery (“EUR”) is an approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well. EUR is not a defined term within the COGE Handbook and therefore any reference to EUR in this Presentation is not deemed to be reported under the requirements of NI 51-101. Readers are cautioned that there is no certainty that the Company will ultimately recover the estimated quantity of oil or gas from such reserves or wells. TSX Ι KEL
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45 Disclaimer Financial Advisories All dollar amounts are referenced in Canadian dollars, except when otherwise noted. Refer to "Non-GAAP Measures and Other Financial Measures" in the Company’s Management’s Discussion and Analysis (“MD&A”) for a quantitative reconciliation of capital expenditures net of A&D, capital expenditures before A&D, funds from operations, adjusted funds from operations, and see the “Capital Resources and Liquidity” section in the MD&A for a quantitative reconciliation of the Company’s net debt (surplus) and see the Petroleum and Natural Gas Sales section in the MD&A for a quantitative reconciliation of the “Net Realized Price”. Non-GAAP Measures and Other Financial Measures This Presentation contains certain non-GAAP financial measures and other specified financial measures, as described below, which do not have standardized meanings prescribed by GAAP and do not have standardized meanings under the applicable securities legislation. As these non-GAAP, and other specified financial measures are commonly used in the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used. Non-GAAP Measures “Operating income” is a non-GAAP measure calculated by deducting royalties, production expenses and transportation expenses from petroleum and natural gas sales, net of the cost of purchases and after realized gains or losses on associated financial instruments. The Company also presents operating income on a per boe basis, referred to as “operating netback”, which allows management to better analyze performance against prior periods, on a comparable basis, and is a key industry performance measure of operational efficiency. See the “Adjusted Funds from Operations” section of Kelt’s Management Discussion and Analysis which provides a reconciliation of the operating income from P&NG sales, which is a GAAP measure. “Net realized price” is a non-GAAP measure and is calculated by deducting the cost of purchases from petroleum and natural gas sales (before royalties), divided by the Company’s production and reflects Kelt’s realized selling prices plus the net benefit of oil blending/marketing activities. In addition to using its own production, the Company may purchase butane and crude oil from fourth parties for use in its blending operations, with the objective of selling the blended oil product at a premium. Marketing revenue from the sale of third- party volumes is included in total petroleum and natural gas sales as reported in the Consolidated Statement of Net Income (Loss) and Comprehensive Income (Loss) in accordance with GAAP. Given the Company’s per unit operating statistics are calculated based on Kelt’s production volumes, management believes that disclosing its net realized prices based on petroleum and natural gas sales after cost of purchases is more appropriate and useful, because the cost of third-party volumes purchased to generate the incremental marketing revenue has been deducted. Net realized prices referenced throughout this Presentation are before derivative financial instruments, except as otherwise indicated as being after derivative financial instruments. TSX Ι KEL
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46 Disclaimer “Capital expenditures, before A&D” and “Capital expenditures, net of A&D” are non-GAAP measures the Company uses to monitor its investment in exploration and evaluation, investment in property plant and equipment, and net investment in acquisition and disposition activities. The most directly comparable GAAP measure is Cash provided by (used in) investing activities. See Kelt’s Management Discussion and Analysis for the full reconciliation to Cash provided by (used in) investing activities. “Net asset value” is calculated by adding the present value of proved plus probable petroleum and natural gas reserves discounted at 10% before tax, undeveloped land value, proceeds from exercise of stock options, and net debt (surplus). “Net asset value per common share” is calculated by dividing the “Net Asset Value” by the diluted number of common shares outstanding. The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are “in-the- money” based on the closing price of Kelt common shares as at the calculation date. Management believes that the “Net asset value” provides a useful measure to analyze the comparative change in the Company’s estimated value on a normalized basis, however it should not be assumed that the “Net Asset Value” represents the fair value of Company’s underlying shares. See the “Net asset value” section of Kelt’s MD&A which provides a reconciliation of the net asset value back to Kelt’s Present value of 2P P&NG reserves, discounted at 10% before tax. “Adjusted earnings before interest and taxes”. Kelt calculates adjusted earnings before interest and taxes (“EBIT”) as net income and comprehensive income plus financing, less accretion of decommissioning obligations, plus deferred income tax expense. Kelt uses adjusted EBIT as a measure of long-term operating performance and as a component in the calculation for return on average capital employed (“ROACE”). “Average capital employed”. Kelt calculates average capital employed as the total of net debt plus the short and long term lease obligations and shareholders equity. Kelt uses average capital employed as a measure of long-term capital management and operating performance, and as a component in the calculation for ROACE. “Return on average capital employed”. Kelt calculates ROACE, expressed as a percentage, as adjusted EBIT divided by the average capital employed. The components adjusted EBIT and average capital employed are non-GAAP financial measures. Kelt uses ROACE as a measure of long-term financial performance. TSX Ι KEL
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47 Disclaimer Capital Management Measures Funds from operations and adjusted funds from operations Management considers funds from operations and adjusted funds from operations key capital management measures as it demonstrates the Company’s ability to meet its financial obligations and cash flow available to fund its capital program. Adjusted funds from operations is not a standardized measure and therefore may not be comparable with the calculation of similar measures by other entities. Adjusted funds from operations per share (basic and diluted) is calculated by dividing the amounts by the basic weighted average common shares outstanding. Net debt and net debt to adjusted funds from operations ratio Management considers net debt and a net debt to adjusted funds from operations ratio as key capital management measures to assess the Company’s liquidity at a point in time and to monitor its capital structure and short-term financing requirements. The “net debt to adjusted funds from operations ratio” is also indicative of the “net debt to cash flow ratio” calculation used to determine the applicable margin for a quarter under the Company’s Credit Facility agreement (though the calculation may not always be a precise match, it is representative). “Net debt” is equal to bank debt, accounts payable and accrued liabilities, net of cash and cash equivalents, accounts receivables and accrued sales and prepaid expenses and deposits. The Company believes that using a “Net debt” non-GAAP measure, which excludes non-cash derivative financial instruments, non-cash lease liabilities, and non-cash decommissioning obligations, provides investors with more useful information to understand the Company’s cash liquidity risk. TSX Ι KEL
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48 Disclaimer Supplementary Financial Measures Production per common share: is calculated by dividing total production by the basic weighted average number of common shares outstanding, in accordance with GAAP. NPV10% BT: the anticipated net present value of the future net cash flow before taxes and after capital expenditures, discounted at a rate of 10%. IRR: Internal rate of return. IRR is the discount rate required to arrive at a NPV equal to zero. Rates of return set forth in this Presentation are for illustrative purposes. There is no guarantee that such rates of return will be achieved in the future. Reserves Replacement: the estimated amount of reserves added to the reserves base during the year relative to the amount of oil and gas produced. IP30 and IP365: the initial production from a well based on operating/producing hours being the first 720 hours (30 days) for IP30 and 365 days for the IP365. Finding, development and acquisition (“FD&A”) cost: is the sum of capital expenditures incurred in the period and the change in future development capital (“FDC”) required to develop reserves. FD&A cost per BOE is determined by dividing current period net reserve additions into the corresponding period’s FD&A cost. Readers are cautioned that the aggregate of capital expenditures incurred in the year, comprised of exploration and development costs and acquisition costs, and the change in estimated FDC generally will not reflect total FD&A costs related to reserves additions in the year. Recycle ratio: is a measure for evaluating the effectiveness of a company’s re-investment program. The ratio measures the efficiency of capital investment by comparing the operating netback per BOE to FD&A cost per BOE. Net asset value per common share: is calculated by adding the present value of petroleum and natural gas reserves, undeveloped land value and proceeds from exercise of stock options, less the present value of decommissioning obligations and bank debt, net of working capital, and dividing by the diluted number of common shares outstanding. The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are “in-the-money” based on the closing price of the common shares as at the calculation date. Per BOE metrics: Net realized price, realized hedging gain (loss), royalties, production expenses, transportation expenses, G&A expense, interest expense, other income (gain) and settlement of decommissioning obligations on a $/BOE basis is calculated by dividing the amounts by the Company’s total production over the period. TSX Ι KEL
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49 Kelt Exploration Ltd. Suite 300, East Tower 311 – Sixth Avenue SW Calgary, Alberta Canada T2P 3H2 T 403.294.0154 F 403.291.0155 www.KeltExploration.com David J. Wilson President & Chief Executive Officer Sadiq H. Lalani Vice President & Chief Financial Officer TSX | KEL