Tuktu Resources Ltd. — Capital/Financing Update 2024

Nov 4, 2024

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A preliminary short form prospectus containing important information relating to Tuktu Resources Ltd. (“Tuktu”) and the securities described in this document has been filed with the securities regulatory authorities in each of the provinces of Canada, other than Québec. The preliminary short form prospectus is still subject to completion.

There will not be any sale or any acceptance of an offer to buy the securities until a receipt for the final short form prospectus has been issued.

This document does not provide full disclosure of all material facts relating to the securities offered. Investors should read the preliminary short form prospectus, the final short form prospectus and any amendment for disclosure of those facts, especially risk factors relating to the securities offered, before making an investment decision.

Overview

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Capitalization[ (1,2)]

Investment Highlights

Share Price	(C$/sh)	$0.10
Basic Shares Outstanding	(mm)	142.9
Dilutives Outstanding	(mm)	137.7
Basic Market Cap	(C$mm)	$14.3
Net Debt (Cash)	(C$mm)	$0.5
Enterprise Value	(C$mm)	$14.8
Production Capacity	(Boe/d)	877
Percent Liquids	(%)	54%

Financing Overview

• Indicative Offering Price: $0.09 per unit

• Target Raise: Up to $10 million (excluding the agent’s overallotment option to purchase an additional $1.5 million)

• Form of Equity: Marketed Offering of Units

Each unit comprising of one common share and one-half of one common share purchase warrant exercisable at $0.13 per warrant

• Agent: Canaccord Genuity Corp.

• Use of Proceeds: Drill development wells at Penny Upper Banff and general working capital

• Expected Closing : November 2024

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Total production of 877 BOE/d comprised of ~ 477 BOE/d(net), and ~ 400 BOE/d sweet gas , with low decline rate

Expansive land holdings with 167 gross (161 net) sections , offering significant development potential

Anticipating a base (without new drilling production income) 2025 net operating income of $6 MM[(3)] , providing a solid base for future opportunities

+100 un-booked[(4)] , high-potential locations across four repeatable plays (three light oil, one sweet gas)

Well production of 24.1 Mbbl in 61 days suggests a high permeability reservoir which may extend over 52 sections (~26.5 gross sections controlled by Tuktu)

(3) Based on an estimated monthly NOI, Dec 2024, then annualized (assuming a $23/BOE netback and 800-850 BOE/d).

(1) Basic shares outstanding, dilutive securities outstanding and net debt are as at June 30, 2024 (2) See “Advisories – Non-GAAP Financial Measures and Ratios”

(4) See “ Advisories – Oil and Gas Advisories – Drilling Locations “.

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Background: Corporate Governance

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Board of Directors

Management

Kathleen Dixon Chair

Former Director, BMO Capital Markets in the Acquisitions and Divestitures Group.

Tim De Freitas President, CEO & Director

25+ experience, CEO, management, technical and COO rolls in numerous public and private oil and gas companies (Talisman, Nexen, Exxon, Pieridae, Ikkuma, Amarok, Manitok, Trilateral, and others) in and outside Alberta

Bob Dales Director

William Guinan Director

Natalie Sweet Director

Funder/co-founder of Kelt Exploration Ltd., Celtic Exploration Ltd., Peyto Exploration and Development Corp., Amarok Energy Inc., and Manitok. Chairman of Ikkuma Resources Corp.

Lawyer at Borden Ladner Gervais LLP from 1982 until 2021. Director and corporate secretary for numerous public and private corporations over the last 30 years

25 years of exploration and development, including Penn West Exploration Ltd., Apache Canada Ltd. and Mount Bastion Oil and Gas Corp.

Mark Smith VP, Finance & CFO

Greg Feltham VP, Exploration

Sumir Saini VP, Land & Business Development

Kent Busby VP, Production

Chartered Professional Accountant with 20+ years experience in oil and gas companies (Breaker Energy, Wildcat Royalty, Caledonian Midstream)

20+ years experience of exploration and development. Experience with structural, conventional and resource plays domestically and international. Prior experience n Manitok Energy, Ikkuma Resources, and Pieridae

20+ years experience, in land & business development; management and executive rolls in Empire Oil Corp., Mount Bastion Oil & Gas, and Bellatrix Exploration; Involved in >$1 billion in M&A transactions.

30+ years experience construction and oilfield operations, including the management of >200 field employees. Senior positions in Pieridae, Manitok, and Ikkuma.

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Driving Competitive Advantage with Innovation and Expertise

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Innovation : Accomplished Team and Board that has a record of finding and developing plays which  have fallen out of favor with many other producers



New Pools at a Low Cost: We operate in regions that have been less active, leveraging lower competition and reduced costs, resulting in favorable acquisition metrics

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Proven Success since Recapitalization: All the below has been accomplished since Tuktu’s  recapitalization transaction in July 2022

 Advanced Technical Expertise: Leveraging complex foothills drilling technologies to tap into structured Deep Basin plays, allowing Tuktu to operate in plays that are a natural fit for the team’s unique skill set

 A Focus on Conventional Reservoirs: These have greater natural permeability and effective porosity that generally exceed those of unconventional reservoirs; less fracture stimulation and less costly to exploit

Company History and Key Milestones

Acquires light oil play in the southern Announces light oil production Alberta Foothills; a mostly paper deal purchase in the southern Alberta deep Closes on private placement of units for $1.3 MM Basin for $3 MM for gross proceeds of$1.35 MM July March April October December May September 2022 2023 2023 2023 2023 2024 2024 Recapitalized by new team and Acquires natural gas assets for $2.25 Closes on private Well recompletion refocus on oil and gas projects; million: 100% sweet gas and an placement of units for announcement injects gross $4.67 MM operated gas plant in southern Alberta gross proceeds of $1.5 MM

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Best-in-Class Acquisition Transactions

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Historic Acquisition Metrics ($/BOE/d) (after Athena Capital)

Long-Term Reserve Development Upside on existing Asset Base

Acquisition 3: Current Asset Acquisition Reserves and Net Present Value of Future Net Revenue [(1,2,5)]

• PDP 0.31 MMbbl, $5.5 million NPV10%

• TPP 2.1 MMbbl, $19.6 million NPV10%

Acquisition 2: Southern Alberta Acquisition Announced March 21, 2023 [(3,5)]

• PDP 727 MBoe ,$3.7 million NPV10%

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Acquisition 2

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Acquisition 3

• TPP 1,449 Mboe, $6.2 million NPV10%

Acquisition 1: Southern Alberta Oil Acquisition, Announced December 8, 2022 [(4,5)]

• PDP 27 MBoe, $0.6 million NPV10%

• TPP 1,329 Mboe, $35.1 million NPV10%

• (1) Represents the Adjusted Purchase Price divided by the estimated 2023 field netback for the asset acquired pursuant to Acquisition 3 (as defined herein), based on a projection of costs and declines of the Vendor’s Lease Operating Statements and on September 20, 2023 Strip Pricing. The “Adjusted Purchase Price” is the purchase price of $3.0 million less estimated interim adjustments of $1.5 million, based on nine months of adjustments.

• (2) Reserves information is based on the Acquisition 3 Reserves Report (as defined herein), see “ Advisories – Oil and Gas Advisories – Reserves Information” .

• (3) Reserves information is based on the Acquisition 2 Reserves Report (as defined herein), see “ Advisories – Oil and Gas Advisories – Reserves Information ”.

• (4) Reserves information is based on the Acquisition 1 Reserves Report (as defined herein), see “ Advisories – Oil and Gas Advisories – Reserves Information”.

• (5) NPV10% means the net present value of future net revenue before income tax discounted at 10%. This metric does not represent the fair market value of the applicable assets. See " Advisories – Oil and Gas Advisories – Reserves Information ".

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Assets positioned across 4 repeatable plays with 100+ Locations

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Tuktu owns 167 gross sections (161 net sections), mostly in light oil-prone reservoirs in the deep basin[(1)]

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Deep Basin
Foothills
Deep Basin, light oil play 1&2 [(1)]
Gas prone structured
Cretaceous reservoirs,
with TUK-100% sweet
gas plant Light oil discovery in
structured, Mississippian
carbonate/clastic reservoir
Legend Foothills, gas play 4 Over pressured deep basin,
light-oil charged; moderately
Eastern limit of
Foothills structured with regional scale
Tuktu Target Area faults and local intense fracture
development
Foothills, light oil play 3
Light sweet oil Cretaceous structured
reservoir, analogous to the prolific
foothills Cardium Stolberg Field
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(1) Plays I and 2 are part of Acquisition 3, which was announced on October 18 , 2023 and closed on May 27, 2024. Certain of these lands are also part of a farm-in agreement announced July 17, 2024.

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Tuktu’s Deep Basin Oil Discovery – Penny Upper Banff

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• In June of this year, Tuktu stimulated a vertical well bore (25-ton slick water frac)

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• Well was on production for 61 days, averaging 386 bbl/d of oil. ( 24.1 Mbbl produced )[(1) ]

• 31.5 API oil; Minimal gas and water (3-4% gas on a BOE basis, and 1-2% water)

• Less than 20% draw-down; now 0% drawdown (rate is limited by pump capacity)

• Sustained production implies high permeability reservoir

Tuktu’s vertical discovery ranks in the top 1% of all vertical wells drilled in the Deep Basin since January 2000[(2)]

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Likely pump-limited production
Well production capability increases
~17% drawdown
0% drawdown
UWI
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The well is presently shut in due to AER regulations, a normal course requirement that ensures conservation of reservoir energy in newly discovered conventional oil pools (anticipated well restart on or about December 1, 2024)

(1) Please see “Advisories – Oil and Gas Advisories – Initial Production Rates”. The 61 days of production data includes an initial 11 days of load fluid recovery. During this time, due to pump rate limitations and load water recovery, oil rates were significantly lower.

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(2) Data on vertical well IP60 rates are from GeoScout . IP60 rates of in situ or Sag D, CSS bitumen wells have been excluded from the population of 14,077 vertical wells placed on production since January 1, 2000.

Penny Upper Banff – Play Summary

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• The area was originally drilled for the lower Banff and Big Valley zones, bypassing the Upper Banff.

• Based on 6 well intersections, Tuktu estimates an exploitable pool size of about 52 sections

• Currently Tuktu holds or has farm-in options on 26.5 sections within the pool, on which we estimate 60-70 drilling locations.[(1)]

• Future drilling plans include the drilling of a horizontal well offsetting the discovery well.

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Exact land position held for competitive purposes

Pool Size: 52 sections Tuktu Land Position: 26.5 sections Estimated unbooked well locations: 60-70[(1)]

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(1) Please see “Advisories – Oil and Gas Advisories – Drilling Locations”.

Banff Reservoir: Horizontal versus Vertical well multiplier

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• Horizontal wells in western Canada and many basins globally are used typically to exploit conventional and unconventional reservoirs

• There are various reasons for using this technology

• Limited well surface footprint

• Accessing natural fractures sets in reservoirs prone to structural deformation

• Increased productivity (“IP” or initial production) and reserves per well , particularly in low permeability reservoirs

• In the case of western Canada, the royalty credit (C) is beneficial to horizonal well economics* by significantly increasing capital efficiency

  • Horizontal well multiplier (“HWM”) can vary significantly in the basin

  • Based on publicly available data, IP and Estimated Ultimate Recovery (“EUR”) multiples can vary between 3 and 40X, depending on the target zone

  • The Cessford Banff pool is a reasonable Banff analogue that may be used to approximate initial rates for horizontal wells in the southern Alberta deep Basin (below table)[(1)]

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(1) Data derived from the “Around the Corner” newsletter published by Canaccord Genuity in October 2024. The data is derived from publicly available information (GeoScout). A comparison is made amongst vertical and offset horizontal wells in the same pool. There are more than 95,000 horizontal wells in Alberta alone that could be used in such comparisons. These horizontal target many procuring zones, including a variety of carbonate and clastic reservoirs.

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Banff Reservoir: Use of Proceeds

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Assumptions

• Access to 26.5 gross sections

• 60 to 70 unbooked horizontal locations

• $2 to $3 million for vertical wells, $5 to $6 million for horizontal wells

• Horizontal wells – IP30: 800 bbl/d, 300 Mbbl[(1)]

• Vertical wells - IP30: 350 bbl/d, 133 Mbbl

Case A – Higher capital raise under the Offering

• Assuming gross proceeds raised of approximately $7 to $10 million

• $5.7 million: One horizontal well (2km lateral with frac’d leg)

• $2.8 million: One vertical / deviated well

• $0.5 million: Unallocated working capital and other corporate purposes

Case B - Lower capital raise under the Offering

• Assuming gross proceeds raised of approximately $5 to $7 million

• $5.7 million: One horizontal well (2km lateral with frac’d leg)

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• $0.5 million: Unallocated working capital and other corporate purposes

			IP HWM of
	Est. CAPEX ($	IP30 (bbl/d,	Offset vertical	Est. Recovery
	millions)	risked)	well	(oil, M<bbl)	IRR(%)	Payout(years)
Vert Well (Crown Royalties)	$2.80	350	88%	147	500%	0.4
HZ Crown Royalties	$5.70	800	200%	305	467%	0.5

Assumptions	Assumptions
WTI (USD)	$70.00/bbl
WTI (CAD)(2)	$97.47/bbl
Quality Discount	$15.00/bbl
Opex	$10.00/bbl
Royalties with C*	5%
Royalties	20%-30%

• (1) Indicative statistics of a HWM could be significantly higher, based on publicly available data. The Company has chosen an approximately 2X HWM. Vertical offsets are risked at 75%. USD/CAD exchange rate data as of October 31, 2024

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Banff Reservoir: A comparison with Tuktu’s Play 1

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The Tuktu deep basin play is the only reservoir of the next 3 examples that has significant fracturerelated permeability enhancement and overpressure (pressure gradient ~14.0 kpa/m)

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Ferguson

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44 sections (27,923 acres; 11,300 ha) 9.5 millions Bbls[(1)]

Fully Developed Field	Fully Developed Field
Porosity	9%
Original ~ GOR	2,800 cf/bbl
Initial Pressure	10,200 kpa
Average Depth	1290m
Thickness	12m
Pressure Gradient	7.8 kpa/m
API	27.2 API
Recovered to date(1)	9.5 million Bbls

Cessford

	water Oil and gas	water Oil and gas
	53 sections(33,606 acres; 13,600 ha)
	7.5 Million Bbls(1)
	Fully Developed Field
	Porosity	8.5%
	Original ~ GOR	n/a
	Initial Pressure	6,600 kpa
	Average Depth	1,350 m
	Thickness	4.2 m
	Pressure Gradient	7 kpa/m
	API	28 API
	Recovered to date(1)	7.5 million Bbls

Tuktu, deep basin

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52 sections[(2)] (33,112 acres; 13,400 ha)

Undeveloped,	Mostly Tuktu
Porosity	9%
Original ~ GOR	n/a
Anticipated Initial	28,300 kpa(3)
Pressure
Average Depth	2,005 m
Thickness	5 m
Pressure Gradient	14 kpa/m(4)
API	31-33 API
Recoverable Barrel	TBD

(1) All log and cumulative production data is from GeoScout.

(2) Tuktu currently owns 27% and after deal closure with private Co.: 50%; see “Advisories - Pro Forma Development Plan”.

(3) The Penny Banff has very few well intersections and only one producing well; there is much greater uncertainty on these values as compared to the numbers for Cessford and Ferguson fields. Also, the later fields are partly under waterflood.

(4) Based on drilling data.

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Other fairways within Tuktu’s portfolio: Plays 3 and 4

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Play 3

	Play 3	Play 3
• G re g • Si • V p • W p p	Foothills as prone structured Cretaceous servoirs, with TUK-100% sweet as plant gnificant regional extent ertical unstimulated wells can roduce up to 12 Bcf ork suspended in this area, ending improvement in gas rices Foothills, sweet gas play 4 Foothills, light oil play 3 Pincher Creek structures 01-11 vertical well Stolb Play 4		• Fractured reservoirs in leading fold structures yield exceptional results • In a report by TD issued during the Stolberg drilling (2010), analysts concluded these to be the most economic Cardium wells in the basin at that time. • Pincher Creek structure is significantly larger and has higher reservoir pressure • 40-50 API oil • Company anticipates installing artificial lift on the current free flowing well on the structure
		Stolb	erg fractured Cardium(1) 5.7 million bbls

(1) Oil production forward projections are mathematical fits of current and historic production and declined to an acceptable minimum production level; these numbers should not be interpreted as reserves of such fields and they are estimates only.

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Development Plan

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Post-Acquisition [(1)]
Q4 2024 - Q2 2025
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• $ 1-2 million expenditure

• Well workovers and recompletions - First recompletion resulted in light oil discovery

• Pump/tubing replacements and installation of artificial lift in one or

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2025-2027 [(4)]
Q2 2025 –
Q4 2025 [(1)]
• Ongoing drilling of deep basin light
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• Ongoing drilling of deep basin light inventory

• Execute Horizontal oil wells in other light oil pools, targeting fracture fairways similar to those of the deep basin light oil discovery

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Total CAPEX [(2,3)] of $5 - 9MM
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  - Drill-from-surface 1 Directional/ Vertical well and 1 Horizonal well along fractured fairway, offsetting current discovery well, pending adequate cash from operations

  - Ongoing well workovers and artificial lift installation of wells which flow intermittently

  - Possibly drill re-entries of existing

     - well bores

• more wells

• (1) Post-completion of: (i) Acquisition 1, pursuant to which Tuktu acquired certain oil properties in Pincher Creek in March 2023; (ii) Acquisition 2, pursuant to which Tuktu acquired certain natural gas properties in Southern Alberta in April 2023; and (iii) Acquisition 3, pursuant to which Tuktu acquired certain oil properties in Southern Alberta in May 2024.

• (2) Estimated risked and unrisked initial rates and declines of individual well rates are based on similar operations conducted by the management team in areas featuring reservoir characteristics and structural configuration similar to the target asset. Initial rates and declines of each recompletion or workover are also based on risked and unrisked results of wells completed nearby in the same reservoirs or on reservoirs elsewhere in the foothills and nearby Deep Basin. See “ Advisories – Oil and Gas Advisories – Analogous Information ". These assumptions are subjective and the results of the development plan may not yield the projected results. Also, all projects are subject to further technical and economic due diligence and board approval of an anticipated pro forma budget. Peak corporate net production rates will also depend on the timing of contemplated recompletion and workover projects.

• (3) Non-GAAP financial measure. See “ Advisories – Non-GAAP and Other Financial Measures ". Some of the anticipated CAPEX could occur in 2024, depending on project timing and fundraising.

• (4) See “ Advisories – Pro-Forma Development Plan ".

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Summary

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Financing Summary

• Indicative Offering Price: $0.09 per unit

• Target Raise: Up to $10 million (excluding $1.5 million over-allotment option)

• Form of Equity: Marketed Offering of Units, each Unit comprising one common share and one-half of one common share purchase warrant exercisable at $0.13 per warrant for a period of 24 months from closing

• Agent: Canaccord Genuity

• Commission: 6% cash commission (3% president’s list), 6% broker warrants[(1) ] (nil president’s list)

• Expected Closing : November 2024

Use of Proceeds

Case A- Higher capital raise ($7-$10 million)

• One horizontal well (1.5-2km lateral with frac’d leg)

• And one deviated well

Case B - Lower capital raise ($5-$7 million)

• One horizontal well (1.5-2km lateral with frac’d leg)

Why Invest

• Proven management team with history of exploiting new play opportunities and growing production.

• Significant exposure to exciting new oil discovery, within small cap O&G public company

• Near term HZ drilling, offsetting one of the best vertical wells in the basin.

• With success, likely to attract larger suitors looking to capitalize on Tuktu’s success

(1) Each Broker Warrant will entitle the holder thereof to one (1) Offered Unit at an exercise price equal to the Offering Price, each Offered Unit comprising of one (1) Underlying Share and one-half of one (1/2) Underlying

Warrant.

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APPENDIX

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Background: About Tuktu Resources Ltd.

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• Industry leading technical and operational team with direct experience owning and developing profitable assets.

Experienced Management Team

• Team has successfully executed a junior growth model twice previously at Manitok Energy Corp. (“ Manitok ”) and Ikkuma Resources Corp. (“ Ikkuma ”).

• Team is ideally positioned to operate Foothills and Deep Basin assets to drive long-term shareholder value.

• Attractively priced consolidation opportunities exist within the Alberta Foothills and Deep Basin with considerable free cash flow and resource upside.

Foothills & Deep Basin Consolidation Opportunity

• Due to the exodus into unconventional plays, previous operators have left underexploited reservoirs and under-utilized infrastructure providing an advantage and cost savings for a junior growth company.

• Parts of the southern Alberta Deep Basin with a high structural component amenable to exploitation skills developed in the foothills.

• The lack of recent development drilling has left Foothills facilities and pipelines underfilled. Operators have plenty of processing capacity and egress for new gas.

• Meaningful investment from insiders

Clean Corporate Entity, Attractive Foothills Oil-Prone Acreage

• Debt-free company

• Minimal asset retirement obligations after giving effect to the previously announced acquisitions of assets from an arm's length, private company (Acquisition 1) and an arm's length company (Acquisition 2 and Acquisition 3)[(1)]

• Pro forma , the Company has identified 100-120 drilling locations across four independent play types on the acquired land base: 30 locations targeting sweet gas and oil within the foothills and 70-90 locations targeting oil in the adjacent deep basin.[(2)] The former 30 horizontal well locations are akin to fields previously developed in the Foothills by the Tuktu management team ( e.g. , Stolberg).[(3) ]

• (1) Specifics of Acquisition 1 were announced December 8, 2022 and specifics of Acquisition 2 and Acquisition 3 were announced via press release on March 21, 2023, and October 18, 2023, respectively.

• (2) See “ Advisories – Oil and Gas Advisories – Drilling Locations ".

• (3) See " Advisories – Oil and Gas Advisories – Analogous Information ".

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Background: Track Record of Success of Tuktu Team Members

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July 2010 to Oct. 2013

May 2014 to Dec. 2018

Dec. 2018 to Jan. 2021

• Went public via a reverse take-over of a public company, with a concurrent $20MM private placement, and a rights offering to existing public company shareholders.

• Mr. de Freitas, in addition to other members of the Tuktu team, joined Pieridae at the closing of the Ikkuma transaction and remained with the company as it undertook the transformational Shell Foothills acquisition in 2019.

• Went public via an amalgamation with private company, previously having raised $18MM in equity via private placements since being founded in 2005, with Mr. de Freitas serving as VP, Exploration and COO.

• Ikkuma subsequently undertook a successful $120MM asset acquisition in the Foothills region funded with a $130MM bought equity deal.

• Completed a number of acquisitions and undertook meaningful exploration and development activities within the Central and Southern Alberta Foothills.

  • The Foothills transaction closed in late-2019, adding ~28,000 BOE/d in the Alberta Foothills, in addition to a number of facilities, for a total purchase price of $190MM. The Tuktu team was integral throughout the acquisition and subsequent integration.

• The team would complete a number of additional acquisitions and equity raises, until Ikkuma was ultimately sold to Pieridae in December 2018 (~300% premium to VWAP). The team additionally negotiated a spin out transaction as part of the sale, driving incremental value for all shareholders.

• Manitok was focused on both heavy oil, and Foothills natural gas, in many of the same areas where the Tuktu team is currently targeting M&A.

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Manitok Historical Production
5,000 60
Production
Prod. per Share
3,750 45
2,500 30
1,250 15
0 0
Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
2010 2011 2012 2013
(BOE/ d)
(BOE/ d per MM Shares)
----- End of picture text -----

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Pieridae Historical Production
50,000 300
Production
Prod. per Share
40,000 240
30,000 180
20,000 120
10,000 60
0 0
Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2018 2019 2020
(BOE/ d)
(BOE/ d per MM Shares)
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Ikkuma Historical Production
25,000 200
Production
Prod. per Share
20,000 160
15,000 120
10,000 80
5,000 40
0 0
Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
2014 2015 2016 2017 2018
(BOE/ d)
(BOE/ d per MM Shares)
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Note: Historical Production Graphs prepared by Stifel Nicolas Canada Inc.

Lower Banff Reservoir: Structural influence on Play 2

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Schematic fault array to demonstrate enhanced permeability fairways across land base[(2)]

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An early mover with a competitive advantage in a producing play

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• Some wells purchased in Acquisition 3 have produced over 400 Mbbl[(1) ] due to enhanced natural fracture fairways that developed due to foothills-related compression and a reactivated normal fault network.

• Total thickness of oil charge in the deep basin is approximately 250 m, in an overpressured (up to 17 kpa/m) envelope with no apparent water.

• Tuktu team is positioned to leverage their foothills drilling and completion experience to exploit such fracture fairways.

• Anticipated HZ wells are expected to greatly exceed those of the vertical well, as has been demonstrated many times in the basin ( e.g., Cardium, Montney, Wilrich reservoirs)

• Fracture intensity and position relative to faults and fracture fairways has been shown to yield exception well results.

Fracture intensity related to extensional faulting

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Torabi, et al., Geofluids , 2019
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• Tuktu will use their foothills drilling and completion experience to develop a repeatable play that is anticipated to be highly economic.

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From, Lemieux, 2000
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• (1) Based on GeoScout data.

• (2) Lands shown as Tuktu lands are the subject of Acquisition 3, closed in escrow and awaiting license transfer approval from the Alberta Energy Regulator.

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Background: Acquisition 3 Metrics

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Purchase Price ("P")(1,6)	$3MM
Adjusted Purchase Price(2)	$1.5MM
Adjusted Purchase Price/2023 Estimated Annualized NOI(3,6,7)	0.7 X
12 Month Trailing Operating Expenses	$33.95/bbl
2023E Production(3)	165 bbl/d
2023 Est. Annualized NOI(3,8)	$2.2MM
Cost Per Flowing Barrel (P/(bbl/d))(4,5,11)	$18,182
Trailing production decline	16%
Reserves	MMbbl(9,12)	NPV10% ($MM)(9,10,12)
PDP	0.3	$5.50
Proven + Probable	2.1	$19.60
Reserves	P/MMbbl(9,11,12)	P/NPV10%(9,10,11,12)
PDP	$9.75	55%
Proven + Probable	$1.44	15%

• (1) Prior to interim or final adjustments.

(2) The Adjusted Purchase Price is the purchase price of $3.0 million less estimated interim adjustments of approximately $1.5 million, based on nine months of adjustments.

• (3) Based on vendor's books and records or a projection of such records, as applicable, with an asset decline of 16% and September 20, 2023 strip pricing.

• (4) May to July 2023, average production, based on the vendor’s lease operating statements.

(5) Calculated using the purchase price/current production

(6) The components of the purchase price (prior to any adjustments) are allocated as follows: (i) $2.4 million to petroleum and natural gas rights; (ii) $599,990 to tangibles; and (iii) $10.00 to miscellaneous interests and seismic rights.

(7) Non-GAAP ratio. See “ Advisories – Non-GAAP and Other Financial Measures ".

(8) Non-GAAP financial measure. See “Advisories – Non-GAAP and Other Financial Measures ".

• (9) Based on the Acquisition 3 Reserves Report. Assumes unadjusted purchase price. See “ Advisories – Oil and Gas Advisories – Reserves Information ".

• (10) NPV10% means the net present value of future net revenue before income tax discounted at 10%. This metric does not represent the fair market value of the Assets. See " Oil and Gas Advisories – Reserves Information ".

• (11) Supplementary financial measure. See " Non-GAAP and Other Financial Measures ".

• (12) See " Oil and Gas Advisories ".

19

Current Capitalization

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TSXV: TUK

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	Current
Stock Price(1)	$0.10
Basic Shares(MM) (2)	142.9
Market Capitalization ($MM)	$14.3
Net Debt(2,3)	$0.5
Enterprise Value ($MM)(3)	$14.8

Options	MM	Price	Proceeds(MM)	Expiry
	1.00	$0.08	$0.08	03/23/2027
	4.65	$0.15	$0.70	07/25/2027
	0.95	$0.15	$0.14	12/13/2027
	6.00	$0.05	$0.30	07/17/2029
Total	12.6	$0.10	$1.22
Warrants	MM	Price	Proceeds (MM)	Expiry
Acquisition (Mar 2023)	10.0	$0.300	$3.00	03/17/2026
Financing (Jul 2022)	51.9	$0.110	$5.71	07/15/2026
Financing (Dec 2023)	31.9	$0.075	$2.39	12/28/2026
Financing (May2024)	28.0	$0.075	$2.10	05/28/2027
**Total **	121.8	$0.108	$13.20
Broker Warrants	MM	Price	Proceeds (MM)	Expiry
Financing (Dec 2023)	1.4	$0.05	$0.07	12/28/2026
Financing (May2024)	1.9	$0.05	$0.10	05/28/2027
Total	3.3	$0.05	$0.17

(1) As of October 31, 2024

(2) As of June 30, 2024.

(3) See “Advisories – Non-GAAP Financial Measures and Ratios”.

20

Term Sheet

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Issuer:

Tuktu Resources Ltd. (the “ Company ”). Treasury offering of up to C$10,000,000 in Units (the “ Offered Securities ”).

Issue:

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Each Unit is comprised of one common share in the capital of the Company (“ Common Share ”) and one-half of one warrant (“ Warrant ”). Each full Warrant is exercisable into one Common Share for price of C$0.13 per Common Share for a period of 24 months from the Closing Date.

Issue Price: C$0.09 per Offered Security (the “ Issue Price ”). Issue Size: Up to C$10,000,000 (the “ Offering ”).

Issue Price:

Over-Allotment Option: The Company has granted Canaccord Genuity Corp. an option to offer for sale up to an additional 15.0% of the Units (or components thereof), at the Issue Price, exercisable in whole or in part at any time for a period of 30 days after and including the Closing Date (the “ Over-Allotment Option ”).

Form of Offering:

Public offering of Offered Securities on a best efforts basis, subject to a formal agency agreement, including standard industry “material adverse change out”, “disaster out”, “regulatory out”, “market out”, “due diligence out” and “breach out” clauses running up to the Closing Date.

The Offered Securities (i) will be distributed in Canada by way of a short form prospectus filed by the Company in all provinces of Canada, except Quebec (the “ Canadian Jurisdictions ”); (ii) may be distributed in the United States to Qualified Institutional Buyers (as defined in Rule 144A under the United States Securities Act of 1933, as amended (the “ U.S. Securities Act ”)) pursuant to an exemption under Rule 144A; and (iii) may be distributed outside Canada and the United States on a basis which does not require the qualification or registration of any of the Company’s securities under domestic or foreign securities laws.

Use of Proceeds:

Listing:

Eligibility:

Agents:

Commission:

Closing Date:

The Company intends to use the net proceeds of the Offering towards its capital expenditure program (to drill development wells at Penny Upper Banff), unallocated working capital and other corporate purposes.

The Company will apply to list the Offered Securities (including the Warrants assuming there is adequate distribution of the Warrants) on the TSX Venture Exchange (the “ Exchange ”). Listing will be subject to the Company fulfilling all of the applicable listing requirements of the Exchange.

The Offered Securities shall be eligible for RRSPs, RRIFs, RDSPs, RESPs, TFSAs, and DPSPs.

Canaccord Genuity Corp. on behalf of a syndicate of agents

The Company will pay to the Agents, on the Closing Date, a cash commission equal to 6.0% of the gross proceeds received pursuant to the Offering (including the Over-Allotment but reduced to 3.0% for gross proceeds from the President’s List). In addition, the Company will issue broker warrants to the Agents equal to 6.0% of the Offered Securities issued pursuant the Offering (including the OverAllotment Option but excluding Offered Securities purchased by purchasers on the President’s List, for which no broker warrants shall be issued). Each broker warrant entitles the holder thereof to acquire one Offered Security at the Issue Price for a period of 24 months from the Closing Date.

On or about November 21, 2024 (the “ Closing Date ”)

21

Advisories

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Prospective investors should rely only on the information contained in the preliminary short form prospectus dated November [4] , 2024 or any amendment thereto (the “ Preliminary Prospectus ”) in respect of the marketed offering (the “ Offering ”) of units of the Company, each unit comprising of one common share and one-half of one common share purchase warrant of the Company (as defined herein). This presentation is qualified in its entirety by reference to, and must be read in conjunction with, the information contained in the Preliminary Prospectus. A prospective investor is not entitled to rely on parts of the information contained in this presentation to the exclusion of others. Neither Tuktu Resources Ltd. (“ Tuktu ” or the “ Company ”) nor Canaccord Genuity Corp. (the " Agent ") have authorized anyone to provide prospective purchasers with additional or different information. Tuktu and the Agent are not offering to sell shares in any jurisdiction where the offer or sale of such securities is not permitted. The contents of this presentation are not to be construed as legal, financial or tax advice. Each prospective investor should contact his, her or its own legal advisor, independent financial advisor or tax advisor for legal, financial and tax advice. No representation or warranty, express or implied, is made or given by or on behalf of Tuktu or any of its directors, officers or employees as to the accuracy, completeness or fairness of the information or opinions contained in this presentation and no responsibility or liability is accepted by any person for such information or opinions.

For prospective purchasers outside Canada, neither Tuktu nor the Agent have done anything that would permit this offering or possession or distribution of the Preliminary Prospectus and final prospectus or any amendment thereto, in any jurisdiction where action for that purpose is required, other than in Canada. Prospective purchasers are required to inform themselves about, and to observe any restrictions relating to, this offering and the possession or distribution of the Preliminary Prospectus and final prospectus. In this presentation, all amounts are in Canadian dollars, unless otherwise indicated. Capitalized terms that are not defined in this presentation have the meanings ascribed to them in the Preliminary Prospectus. Any graphs, tables or other information in this presentation demonstrating the historical performance of Tuktu, its management team, or any other entity contained in this presentation are intended only to illustrate past performance of such entities and are not necessarily indicative of future results of the Company.

There is no minimum amount of funds that must be raised under this Offering. This means that the Company could complete this Offering after raising only a small proportion of the Offering amount set out in the Prospectus.

FORWARD-LOOKING INFORMATION ADVISORIES

Certain information contained in this document may constitute forward-looking statements and information (collectively, "forward-looking statements") within the meaning of applicable securities legislation that involve known and unknown risks, assumptions, uncertainties and other factors. Forward-looking statements may be identified by words like "anticipates", "estimates", "expects", "indicates", "intends", "may", "could" "should", "would", "plans", "target", "scheduled", "projects", "outlook", "proposed", "potential", "will", "seek" and similar expressions (including negatives and variations thereof). Forward-looking statements in this document include, among other things, statements about: Tuktu and its business strategy, strengths, focus and objectives; the Offering, including the success, timing and anticipated use of proceeds thereof; the anticipated annual decline of the Company’s assets (including recently acquired assets); financial and operating forecasts with respect to the Company’s assets; that the Company will be able to implement a well workover/recompletion program and the anticipated production growth resulting therefrom; projections with respect to operating expenditures and capital expenditures; pro forma company asset metrics; pro forma capitalization expectations; growth targets; anticipated pro forma drilling locations; expectations with respect to raising future capital; expectations with respect to funding and approval of the Company’s Development Plan (as defined herein); expectations that a development drilling program will follow the Company's recompletion plan and the timing thereof; NOI per expected outstanding share amounts; and other similar statements. Such statements reflect the current views of management of the Company with respect to future events and are subject to certain risks, uncertainties and assumptions that could cause results to differ materially from those expressed in the forward-looking statements.

Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Tuktu's actual production (including production from recently acquired assets), revenues, taxes and development and operating expenditures with respect to their respective reserves will vary from estimates thereof and such variations could be material.

With respect to forward-looking statements contained in this document, the Company has made assumption as specifically detailed throughout this document and assumptions regarding, among other things: the completion of the Offering; that the Company will be able to raise adequate funds in the future; the geological characteristics of Tuktu’s properties, including recently-acquired assets; the success of future drilling, development and completion activities; future commodity pricing and related supply demand; future exchange, inflation, and interest rates; that the Company will be able to exploit the Mississippian aged reservoirs in the land base; that the Company will be able to successfully implement a well workover/recompletion program to increase production; the receipt and timing of regulatory and other required approvals; and operating costs and capital expenditures.

Factors that could cause actual results to vary from forward-looking statements or may affect the operations, performance, development and results of the Company's businesses include, among other things: risks and assumptions associated with operations; the Company's ability to raise future funds including the ability of the Company to fund its pro forma development plan; the failure to receive regulatory approvals to satisfy the conditions to completion of the Offering; risks inherent in the Company's future operations; the Company's ability to generate sufficient cash flow from operations to meet its future obligations; the Company's ability to exploit the Mississippian aged reservoirs in the land base; the Company's ability to implement a well workover/recompletion program to increase production; risks regarding the Company's ability to reduce operating costs and increase production; increases in maintenance, operating or financing costs; the realization of the anticipated benefits of future acquisitions, if any; the availability and price of labour, equipment and materials; competitive factors, including competition from third parties in the areas in which the Company intends to operate, pricing pressures and supply and demand in the oil and gas industry; fluctuations in currency and interest rates; inflation; risks of war, hostilities, civil insurrection, pandemics, instability and political and economic conditions (including the ongoing Russian-Ukrainian and Israeli-Hamas conflicts and the results of the upcoming U.S. election); inclement and severe weather events and natural disasters; terrorist threats; risks associated with technology; risks associated with the oil and gas industry in general; changes in laws and regulations, including environmental, regulatory and taxation laws, and the interpretation of such changes to the management team's future business; availability of adequate levels of insurance; difficulty in obtaining necessary regulatory approvals and the maintenance of such approvals; general economic and business conditions and markets; and such other similar risks and uncertainties. The impact of any one assumption, risk, uncertainty or other factor on a forward-looking statement cannot be determined with certainty, because these are interdependent, and the Company's future course of action depends on the assessment of all current available information.

The forward-looking statements contained in this document are made as of the date hereof and the parties do not undertake any obligation to update or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. These and other risks are set out in more detail in Tuktu’s annual information form for the year ended December 31, 2023 (“AIF”) and Tuktu’s most recent annual and interim management discussion and analysis (“MD&A”). The Company’s AIF and MD&A can be accessed under Tuktu’s SEDAR+ profile at www.sedarplus.ca.

22

Advisories

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PRO FORMA DEVELOPMENT PLAN

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The Company has presented herein an illustrative pro-forma development plan (the “ Development Plan ”) in respect of Tuktu's assets, including the assets acquired pursuant to Acquisition 1, Acquisition 2 and Acquisition 3 (as further described on Slide 13). The Development Plan is based on a number of assumptions including, without limitation: the required reinvestment rates to maintain production; the Company's ability to raise future funds; expected recovery factors; average production per year resulting from such development plan; expected cash flow and free cash flow; capital expenditures per year; expectations as to commodity prices, royalty rates, production costs, general and administrative expenses and certain other assumptions. The Development Plan has not been approved by the Board of Directors of the Company and is not intended to present a forecast of future performance or a financial outlook. In addition, the Development Plan does not represent management's expectations of the Company's future performance but rather is intended to present readers insight into management's view of opportunities available to Tuktu as of the date of this document, as used by management for planning and strategy purposes based on the commodity pricing and other assumptions used for such strategy. The Development Plan does not represent an estimate of reserves or the future net present value of reserves. There is no certainty that the Company will proceed with any of the projects contemplated by the Development Plan , and even if the Company does proceed with such plans, there is no certainty that the oil and gas recovered will match the expectations used for such plan. All future capital expenditures will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, debt levels, actual drilling results, additional reservoir information that is obtained, and other factors. The assumptions used for the plan presented herein are subject to a number of risks including the risks set out under the forward-looking advisory set out above.

The Company continues to negotiate land arrangements with adjacent landowners on the newly acquired land (Acquisition 3); there can be no guarantee that such lands can be successfully acquired until the final points of the agreements are negotiated. If the land agreements cannot be completed in a timely manner or in a manner that is beneficial to all parties, this does not comprise the company’s ability to execute on its capital program.

FORWARD LOOKING FINANCIAL INFORMATION

This document contains future-oriented financial information and financial outlook information (collectively, “ FOFI ") about the Development Plan, anticipated capital expenditures in 2024 and 2025, anticipated 2025 net operating income, and prospective operational and financial results of the Company’s assets, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this document was made as of the date of this document and was provided for the purpose of providing further information about the Company's future business operations, the Company disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities laws. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein.

NON-GAAP AND OTHER FINANCIAL MEASURES

This document uses various specified financial measures (as such terms are defined in National Instrument 52-112 – Non-GAAP Disclosure and Other Financial Measures Disclosure (" NI 51-112 ")) including "non-GAAP financial measures", "non-GAAP ratios" and "supplementary financial measures" (as such terms are defined in NI 51-112), which are described in further detail below. Management believes that the presentation of these non-GAAP measures provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis. These non-GAAP and other financial measures are not standardized financial measures under IFRS and might not be comparable to similar measures presented by other companies where similar terminology is used. Investors are cautioned that these measures should not be construed as alternatives to or more meaningful than the most directly comparable IFRS measures as indicators of the Company's performance.

Non-GAAP Financial Measures and Ratios

• Net Operating Income (" NOI "), non-GAAP financial measure

Management feels net operating income is a key industry benchmark and measure of operating performance of the Company that assists management and investors in assessing the Company's profitability and is commonly used by other petroleum and natural gas producers. Net operating income is calculated as petroleum and natural gas revenue less royalties, transportation and operating expenses.

• Enterprise Value, non-GAAP financial measure

The Company uses "enterprise value" as a key performance indicator. Enterprise value is calculated by adding the Company's market capitalization and market value of the Company's outstanding debt, less any cash or cash equivalents.

• Net Debt

Net debt is a capital management measure which management uses to assess the Corporation’s liquidity. Net debt is calculated as taking the current assets less current liabilities, excluding the warrant liability and current portion of decommissioning obligations.

23

Advisories

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• Adjusted Purchase Price/2023 Estimated Annualized NOI, non-GAAP ratio

Management considers Adjusted Purchase Price/2023 Estimated Annualized NOI a key performance metric for Acquisition 3. Adjusted Purchase Price/2023 Estimated Annualized NOI is determined by dividing the purchase price for Acquisition 3, as adjusted, by 2023 estimated annualized NOI .

Supplementary financial measures

This document may contain certain supplementary financial measures. NI 52-112 defines a supplementary financial measure as a financial measure that: (i) is intended to be disclosed on a periodic basis to depict the historical or expected future financial performance, financial position or cash flow of an entity; (ii) is not disclosed in the financial statements of the entity; (iii) is not a non-GAAP financial measure; and (iv) is not a non-GAAP ratio.

The Company calculates: "Purchase Price/PDP NPV10%" by dividing the Purchase Price by the net present value of the proved developed producing reserves discounted at 10%; "Purchase Price/Proven NPV10%" by dividing the Purchase Price by the net present value of the proven reserves discounted at 10%; "Purchase Price/Proven + Probable NPV10%" by dividing the Purchase Price by the net present value of the proven and probable developed producing reserves discounted at 10%; "Purchase Price/PDP" by dividing the Purchase Price by the estimated proved developed producing reserves; "Purchase Price/Proven" by dividing the Purchase Price by the estimated proven reserves and "Purchase Price/2P" by dividing the Purchase Price by the estimated total proved plus probable reserves.

OIL AND GAS ADVISORIES

RESERVES INFORMATION: All reserves information in this presentation relating to: (i) the assets acquired pursuant to Acquisition 3 are based on the evaluations prepared by GLJ Ltd. (" GLJ ") as set out in a report dated effective December 31, 2022, evaluating the oil reserves attributable to such assets (the " Acquisition 3 Reserves Report "); (ii) the assets acquired pursuant to Acquisition 2 are based on evaluations set out in a report prepared by independent reserves evaluator, GLJ dated effective January 1, 2023, evaluating the reserves attributable to such assets (the “Acquisition 2 Reserves Report ”); and (iii) in respect of the assets acquired pursuant to Acquisition 1 are based on evaluations as set out in a report prepared by independent reserves evaluator, Chapman Petroleum Engineering Ltd. (“ Chapman ”) dated effective June 30, 2022 (the “Acquisition 1 Reserves Report ”), evaluating the reserves attributable to such assets. Each of the Acquisition 3 Reserves Report, the Acquisition 2 Reserves Report and the Acquisition 1 Reserves Report were prepared in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“ NI 51-101 ”) and the most recent publication of the Canadian Oil and Gas Evaluation Handbook (the " COGEH "). The Acquisition 3 Reserves Report and the Acquisition 2 Reserves Reports were based on the average price and market forecasts of three independent reserves evaluators (GLJ, McDaniel & Associates Consultants Ltd. and Sproule Associates Ltd.) as of January 1, 2023 which is set forth under the heading "Pricing Assumptions" on the next slide. The Acquisition 1 Reserves Report was based on the average forecast pricing of Chapman and inflation rates and foreign exchange rates as at July 1, 2022. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of the crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

This document contains estimates of the NPV of the Company's future net revenue from reserves associated with the Company’s assets (including assets acquired pursuant to recent acquisitions), as applicable. Such amounts do not represent the fair market value of such reserves. The recovery and reserve estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. The NPV of the respective assets' base production is a snapshot in time and is based on the reserves evaluated using the applicable pricing assumptions described above. The NPV is calculated using a discount rate of 10%, on a before tax basis and is the sum of the present value of proved plus probable developed producing reserves based on the applicable pricing assumptions. It should not be assumed that the undiscounted or discounted NPV of future net revenue attributable to the respective assets represents the fair market value of those assets. The estimates for reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. The recovery and reserve estimates of crude oil, NGL and natural gas reserves are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates relied upon for NPV calculations, herein.

BOE ADVISORY: The term "BOE" or barrels of oil equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (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. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value.

INITIAL PRODUCTION RATES: References in this document to IP, IP30 or IP60 rates, other short-term production rates or initial performance measures relating to new wells 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 not indicative of long-term performance or of ultimate recovery. All IP rates presented herein represent the results from wells after all "load" fluids (used in well completion stimulation) have been recovered. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.

24

Advisories

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DRILLING LOCATIONS: This document discloses drilling locations in two categories: (i) booked locations; and (ii) unbooked locations. Booked locations identified in this document reflect drilling locations that have associated proved and/or probable reserves, as applicable, and were derived from: (i) in respect of the assets acquired pursuant to Acquisition 3, from the Acquisition 3 Reserves Report; (ii) in respect of Tuku’s assets, from the Acquisition 1 Reserves Report. In respect of the assets acquired pursuant to Acquisition 3, of the 70 gross drilling locations identified herein, 6 gross locations are booked locations, and 64 gross locations are unbooked locations. In respect of Tuktu, of the 20+ gross drilling locations identified herein, 4 gross locations are booked locations, and 16+ gross are unbooked locations. Each of the Acquisition 3 Reserves Report, the Acquisition 2 Reserves Report and the Acquisition 1 Reserves Report were prepared in accordance with NI 51-101 and the COGEH. Unbooked drilling locations are the internal estimates of Tuktu based on the prospective acreage of the Tuktu assets (including recently acquired assets), and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by Tuktu's management as an estimation of Tuktu's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Tuktu will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Tuktu will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been de-risked by Tuktu drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management of Tuktu 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.

ANALOGOUS INFORMATION & TYPE CURVES : Certain information in this document may constitute "analogous information" as defined in NI 51-101, with respect to Tuktu’s assets including, but not limited to, information relating to well locations that are in geographical proximity to or believed to be on-trend with other drilling locations acquired by the Company. This analogous information is derived from publicly available information sources which the Company believes are predominantly independent in nature. Some of this data may not have been prepared by qualified reserves evaluators or auditors and the preparation of any estimates may not be in strict accordance with COGEH. There is no certainty that the results of the analogous information or inferred thereby will be achieved by the Company and such information should not be construed as an estimate of future production levels or the actual characteristics and quality of the Company’s assets. Certain type curves disclosure presented herein represents volumes expected to be recovered from wells. The type curves represent what management thinks an average well will achieve, based on methodology that is analogous to wells with similar geological features. Individual wells may be higher or lower but over a larger number of wells, management expects the average to come out to the type curve. Over time, type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells

THIRD PARTY INFORMATION

Certain market, third party and industry data contained in this presentation is based upon information from government or other industry publications and reports or based on estimates derived from such publications and reports. Government and industry publications and reports generally indicate that they have obtained their information from sources believed to be reliable, but the Company has not conducted its own independent verification of such information. No representation or warranty of any kind, express or implied, is made by the Company as to the accuracy or completeness of the information contained in this document, and nothing contained in this report is, or shall be relied upon as, a promise or re-report by the Company.

OIL AND GAS METRICS: This document contains certain oil and gas metrics which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this document to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the Company's performance in previous periods and therefore such metrics should not be unduly relied upon.

PRICING ASSUMPTIONS

	Edmonton Light
	$CAD/bbl
2023	$103.77
2024	$97.74
2025	$95.27
2026	$95.58
2027	$97.07
2028	$99.01
2029	$100.99
2030	$103.01
2031	$105.07
2032	$106.69
2033	$111.00
2034	$113.22
2035	$115.49
2036	$117.80
Escalating at	2%

US DISCLAIMER

This presentation does not constitute an offer of the securities for sale in the United States. The securities have not been registered under the U S Securities Act of 1933 as amended, and may not be offered or sold in the United States absent registration or an exemption from registration. This presentation shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there by any sale of the securities in any state in which such offer, solicitation or sale would be unlawful.

ABBREVIATIONS

Terms and abbreviations that are used in this document that are not otherwise defined herein are provided below:

API – American Petroleum Institute Mboe – million barrels of oil equivalent bbl(s) - barrel(s) MM - millions bbls/d - barrels per day MMbbl - million barrels of oil Bcf – billion cubic feet Mcf - thousand cubic feet boe - barrels of oil equivalent (6 Mcf = 1 bbl) NPV - net present value boe/d – barrels of oil equivalent per day NPV10 - net present value using a 10% discount rate CAPEX – capital expenditures NGL - natural gas liquids as defined in NI 51-101 IP30 - initial production over the first 30-days on stream PDP - proved developed producing kpa - kilopascal TPP - total proved plus probable Mbbl - thousand barrels of oil NOI - net operating income

API – American Petroleum Institute

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