ANNUAL INFORMATION FORM ("AIF")
FOR THE YEAR ENDED DECEMBER 31, 2025

Dated April 21, 2026

150907145 v3

PRESENTATION OF INFORMATION...1
FORWARD-LOOKING INFORMATION AND STATEMENTS...3
SPECIFIED FINANCIAL MEASURES...6
OIL AND GAS INFORMATION...6
CORPORATE STRUCTURE...7
CORPORATE HISTORY...8
DESCRIPTION OF BUSINESS...11
RESERVES DATA AND OTHER OIL AND GAS INFORMATION...18
DIVIDENDS...27
DESCRIPTION OF CAPITAL STRUCTURE...27
MARKET FOR SECURITIES AND TRADING HISTORY...28
PRIOR SALES...29
DIRECTORS AND OFFICERS...30
LEGAL PROCEEDINGS AND REGULATORY ACTIONS...32
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...32
TRANSFER AGENT AND REGISTRAR...32
MATERIAL CONTRACTS...32
INTERESTS OF EXPERTS...32
INDUSTRY CONDITIONS...33
RISK FACTORS...51
ADDITIONAL INFORMATION...76

APPENDICES

Appendix A - Report on Reserves Data by Deloitte Canada LLP (51-101F2)
Appendix B - Report of Management and Directors on Oil and Gas Disclosure (51-101F3)

PRESENTATION OF INFORMATION

Throughout this Annual Information Form, the terms "Tuktu", the "Corporation", "we" and "our" refer to Tuktu Resources Ltd.

Certain terms used but not defined herein are defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), CSA Notice 51-324 – Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities ("CSA 51-324") and in the most recent publication of the Canadian Oil and Gas Evaluation Handbook Volume I (the "COGE Handbook"). Unless otherwise specified, information in this Annual Information Form ("Annual Information Form" or "AIF") is as at the end of the Corporation's most recently completed financial year (December 31, 2025).

All dollar amounts in this AIF are in Canadian dollars, unless otherwise stated. Words importing the singular also include the plural, and vice versa, and words importing one gender include all genders.

Certain portions of Tuktu's audited financial statements ("Financial Statements") and Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2025 are incorporated by reference into this Annual Information Form. The Financial Statements and MD&A are available on the Corporation's SEDAR+ profile at www.sedarplus.ca.

All references in this Annual Information Form to management are to the persons who are identified in this Annual Information Form as the executive officers of the Corporation. See "Directors and Officers". All statements in this Annual Information Form made by or on behalf of management are made in their capacity as executive officers of the Corporation and not in their personal capacities.

This Annual Information Form contains information relating to Tuktu's business as well as historical and projected future performance, Tuktu's expectations, forecasts and guidance and other market data. When considering these data, investors should bear in mind that historical results and market data may not be indicative of the future results that investors should expect from Tuktu.

The information found on, or accessible through, Tuktu's website does not form part of this Annual Information Form. A reference to an agreement means the agreement, as it may be amended, supplemented or restated from time to time. Figures, columns, and rows presented in tables provided in this AIF may not add due to rounding.

This Annual Information Form includes a summary description of certain material agreements of the Corporation. See "Material Contracts". The summary description discloses attributes that the Corporation considers material to an investor in the common shares of the Corporation ("Common Shares") but is not complete and is qualified in its entirety by reference to the terms of the material agreements, which have been filed with the applicable Canadian securities regulatory authorities and available on SEDAR+. Investors are encouraged to read the full text of such material agreements.

Certain market, independent third-party and industry data contained in this AIF is based upon information from government or other independent 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 Corporation has not conducted its own independent verification of such information. While the Corporation believes this data to be reliable, market and industry data is subject to variations and cannot be verified with complete certainty due to limits on the availability and reliability of raw data, the voluntary nature of the data gathering process and other limitations and uncertainties inherent in any statistical survey. The Corporation has not independently verified any of the data from

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independent third-party sources referred to in this Annual Information Form or ascertained the underlying assumptions relied upon by such sources.

This Annual Information Form contains a number of references to industry specific terminology that is commonly used in the oil and gas business and is also used by the Corporation in this AIF.

Abbreviations

Natural Gas		Oil and Liquids
Mcf	thousand cubic feet	Bbl	barrels
Mcfe	thousand cubic feet equivalent	Mbbl	thousand barrels
MMcf	million cubic feet	MMbbl	million barrels
Bcf	billion cubic feet	Bbl/d	barrels per day
Bcfe	billion cubic feet equivalent	m³	cubic meters
Mcf/d	thousand cubic feet per day	Boe	barrels oil equivalent
e³m³	thousand cubic meters	Mboe	thousands of barrels oil equivalent
MMBtu	million British thermal units	MMboe	millions of barrels oil equivalent
Gj	gigajoule	Tcf	Trillion cubic feet

Volume Conversions

The Corporation reports production and reserves in either Mcf equivalent (Mcfe) or barrels of oil equivalent (boe). Mcfe and boe may be misleading, particularly if used in isolation. In accordance with NI 51-101, Mcfe-to-boe conversion of crude oil and natural gas is 1 bbl: 6 Mcf, which is based on an energy equivalency conversion. The conversion is not intended to represent a value equivalency at the wellhead.

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

From	To	Multiply by
Mcf	m³	28.317
bbl	m³	0.159
m³	bbl	6.29
meters	feet	3.281
kilometers	miles	0.621
miles	kilometers	1.609
acres	hectares	0.405
hectares	acres	2.471
Gj	MMBtu	0.950

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Other

M$	thousands of dollars
$/boe	dollar per barrel of oil equivalent
$/bbl	dollar per barrel
$/MMbtu	dollar per million British thermal units
ha	Hectare
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale
AECO	the natural gas storage facility located at Suffield, Alberta, connected to TransCanada's Alberta System
m³	Cubic metres
MTPA	million tonnes per annum
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for standard grade crude oil

FORWARD-LOOKING INFORMATION AND STATEMENTS

Shareholders and prospective investors are cautioned not to place undue reliance on forward-looking information contained herein. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Forward-Looking Information and Statements

Certain information and statements contained in this Annual Information Form constitute forward-looking information and statements within the meaning of applicable securities laws (collectively, "forward-looking information"). This forward-looking information may relate to future events or to Tuktu's future performance. All statements other than statements of historical fact may be forward-looking information. The use of any of the words "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "believe", "outlook", "guidance", "objective", "plans", "intends", "targeting", "could", "potential", "outlook", "strategy" and any similar expressions (including negatives and variations thereof) are intended to identify forward-looking information.

In particular, but without limiting the foregoing, this Annual Information Form contains forward-looking information pertaining to the following:

the performance characteristics of the Corporation's properties, including quantity and recoverability of the Corporation's reserves;
the Corporation's strategy to focus on the Monarch (Banff) oil play in southern Alberta and to evaluate the divestiture of non-core assets;
the Corporation's exploration, development, seismic acquisition, and production optimization activities, plans and strategies;
the Corporation's acquisition strategy and the existence of acquisition opportunities, the criteria to be considered in connection therewith and the benefits to be derived therefrom;
the ability of the Corporation to achieve success and growth consistent with management's expectations;

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future growth in the Corporation's adjusted funds flow (and its sensitivities to commodity price, production, foreign exchange and interest rate changes);
expectations regarding the Corporation's growth and asset profile (including those assets in the process of being acquired by the Corporation);
future commodity prices as well as supply and demand for natural gas and oil;
the existence, operations and strategy of the Corporation's commodity price risk management program including forward sales and the Corporation's market diversification strategy and contracts;
amount and timing of future abandonment and reclamation costs, decommissioning and environmental obligations;
the use of exploration and development activity, prudent asset management, and acquisitions to sustain, replace or add to reserves and production or expand the Corporation's asset base;
expected book value and related tax value of the Corporation's assets and prospect inventory and estimates of net asset value;
projections of market prices and costs, including operating, general and administrative and other expenses;
expectations regarding the Corporation's ability to raise capital to fund its acquisition, exploration and development activities;
treatment under governmental regulatory regimes (including in respect of royalty rates, income taxes and tax pools);
future drilling, workovers and recompletions estimated in Tuktu's prospect inventory;
reliance on third parties in the industry to develop and expand the Corporation's assets and operations;
the Corporation's plans to further explore and develop its Monarch property and other areas of interest;
the Corporation's plans to evaluate the divestiture of non-core assets and to seek the release of all or a portion of the Corporation's Alberta Energy Regulator security deposits;
the impact of recent management transition, including the appointment of a new President and Chief Executive Officer and a new Chief Financial Officer, and the ability of the new management team to execute the Corporation's revised corporate strategy; and
the results and implications of the Corporation's first horizontal well program in the Monarch area, including expectations for future exploration and development activity informed by geological and engineering data.

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 resources and reserves described can be profitably produced in the future. See "Statement of Reserves Data and Other Oil and Gas Information".

The forward-looking information contained in this Annual Information Form reflects several material factors and expectations and assumptions of the Corporation regarding, among other things: the ability of Tuktu to conduct its operations in a manner consistent with its expectations and, where applicable, consistent with past practice; the general continuance of current or, where applicable, assumed industry conditions; the continuance of existing, and in certain circumstances, the implementation of proposed tax, royalty and regulatory regimes; the ability of Tuktu to obtain equipment, services, and supplies in a timely manner to carry out its activities; the accuracy of the estimates of Tuktu's reserve volumes; the timely receipt of required regulatory approvals; certain commodity price and other cost assumptions; the ability to secure adequate product transportation; government regulations, laws, tariffs and other restrictive trade measures; the continued availability of adequate debt and/or equity financing and funds flow to fund the Corporation's capital and operating requirements as needed; the extent of Tuktu's liabilities; and future oil and natural gas prices, exchange rates and inflation rates.

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Tuktu believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct. The forward-looking information included in this Annual Information Form are not guarantees of future performance and should not be unduly relied upon. Such forward-looking information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation:

volatility in market prices for oil, natural gas, NGL, power and other products, stock market volatility and market valuations (including pursuant to determinations made by OPEC+ regarding production levels);
limited, unfavourable, or a lack of access to capital, including in respect of equity and/or debt markets;
changes in exploration or development plans by Tuktu or by its third party operators;
political or economic developments, including, without limitation, the risk that: (i) the U.S. administration imposes or maintains tariffs on Canadian goods, including oil and gas, and that such tariffs (and/or the Canadian government's response to such tariffs (including the implementation and impacts of retaliatory tariffs)) adversely affect the demand and/or market price for the Corporation's products and/or otherwise adversely affects the Corporation, including risks arising from the scheduled review of the Canada-United States-Mexico Agreement ("CUSMA" or "USMCA") in July 2026; (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension, the Canadian oil and natural gas industry and the Corporation;
the potential impact on energy, tax, and climate policy resulting from the Canadian federal election held in April 2025, and any resulting changes in government policy direction;
reliance on industry partners;
supply and demand regarding Tuktu's products;
risks inherent in Tuktu's operations, such as production declines, unexpected results, geological, technical, or drilling and process problems;
unanticipated operating events that can reduce production or cause production to be shut-in or delayed, including plant upsets, transportation bottlenecks and market disruptions;
unanticipated well or facility operating performance that impacts storage operations or working gas capacity;
uncertainties or inaccuracies associated with estimating reserves and resource volumes;
competition for, among other things, capital, acquisitions of reserves, undeveloped lands, skilled personnel, equipment for drilling, completions, facilities and pipeline construction and maintenance;
increased service and operational costs (including due to inflationary pressures);
incorrect assessments of the value of acquisitions;
royalties payable in respect of Tuktu's production;
fluctuation in foreign exchange or interest rates;
political uncertainty, geopolitical conflicts, hostilities, civil insurrections and wars;
effects of inclement and severe weather events, including fire, drought, flooding and extreme cold temperatures;
government regulation and changes in laws applicable to the Corporation, royalty rates, or other regulatory matters (including adverse regulatory rulings, orders and decisions);
general economic conditions in Canada, the United States and globally; and

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certain other risks detailed from time to time in Tuktu's public disclosure documents including, without limitation, those risks and contingencies described above and under "Risk Factors" in this Annual Information Form.

Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this AIF are expressly qualified by this cautionary statement. Except as required by applicable securities laws, Tuktu does not undertake any obligation or is not under any duty to publicly update or revise any forward-looking statements. Readers should also carefully consider the matters discussed under the heading "Risk Factors" in this AIF.

SPECIFIED FINANCIAL MEASURES

Certain financial terms and measures contained in, or referred to, in the documents incorporated by reference into, this AIF are "specified financial measures" (as such term is defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure ("NI 52-112")). The specified financial measures contained in, or referred to, in the documents incorporated by reference into, this Annual Information Form are comprised of "non-GAAP financial measures", "non-GAAP ratios", "capital management measures" and "supplementary financial measures" (as such terms are defined in NI 52- 112). These measures are defined, qualified, and where required, reconciled with the nearest GAAP measure in the MD&A under the heading "Non-GAAP and Other Financial Measures", which section is incorporated by reference herein. For more information regarding these specified financial measures, including reconciliations, see the Corporation's MD&A for the year ended December 31, 2025, available under the Corporation's profile on SEDAR+ at www.sedarplus.ca. See also "Abbreviations", "Volume Conversions" and "Forward-Looking Information and Statements".

OIL AND GAS INFORMATION

The reserves information contained in this Annual Information Form has been prepared in accordance with NI 51-101 and COGE Handbook. The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied.

Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions. The recovery and reserve estimates of oil, natural gas liquids and natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. The estimated future net revenue from the production of the Corporation's reserves does not represent the fair market value of the Corporation's reserves.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a) for Proved reserves, at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimation; and

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(b) for Proved plus Probable reserves, at least a 50 percent probability that the quantities actually recovered will equal or exceed the estimation.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Selected Oil and Gas Terms

In this AIF, unless otherwise indicated or the context otherwise requires, the following terms used in the preparation of the Deloitte Report (as defined herein) in accordance with NI 51-101 and this AIF have the meanings set forth below. These definitions are generally as set forth in the COGE Handbook and NI 51-101 and are reproduced below for the convenience of the reader.

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time.

"developed non-producing reserves" are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

"developed producing reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if they shut in, they must have previously been on production, and on the date of resumption and production must be known with reasonable certainty.

"reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

"probable reserves" are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

"proved reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"undeveloped reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

CORPORATE STRUCTURE

The Corporation was incorporated under the Business Corporations Act (Alberta) (the "ABCA") as "Jasper Mining Corporation" ("Jasper Mining") on November 28, 1994. On July 15, 2022, the Corporation completed a recapitalization transaction (the "Recapitalization Transaction"), pursuant to which the Corporation: (a) appointed a new management team; and (b) appointed a new board of

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directors (the "Board"). On October 19, 2022, changed its name from "Jasper Mining Corporation" to "Tuktu Resources Ltd." As of December 31, 2025, the Corporation had no subsidiaries.

The common shares of the Corporation (the "Common Shares") are listed for trading on the TSX Venture Exchange (the "TSXV") under the symbol "TUK".

The Corporation's head office is located at Suite 1750, 444 – 5th Ave SW, Calgary, Alberta, T2P 2T8. The registered office of the Corporation is located at 4200 Bankers Hall West, 888 – 3rd Street SW, Calgary, Alberta T2P 5C5.

CORPORATE HISTORY

Pre-Recapitalization (1994-2022)

From 1994 to 2022, Jasper Mining engaged mainly in the exploration of various base and precious metal deposits, mostly within British Columbia. The suite of mining claims held by the Corporation changed from time-to-time over the 28 years. In 2022, at the time of the Recapitalization Transaction, the Corporation held 4 claims (Isintok, Ruth Vermont, McLaren, and Irony) all in the province of British Columbia. In 2014, Jasper Mining sold its Irony claim comprised of lead-zinc sedimentary exhalative deposits ("SEDEX"), to Selkirk Metals Corporation ("Selkirk Metals", a wholly owned subsidiary of Imperial Metals Corporation), and retained a net smelter royalty of 1.5%.

Financial Year Ended December 31, 2023

On March 20, 2023, Tuktu completed the arm's length acquisition of certain oil and gas assets in the Southern Alberta Foothills ("Acquisition 1").

The assets acquired pursuant to Acquisition 1 comprise 19 gross sections over a buried fold structure which carries light sweet oil-charged reservoirs of Jurassic to Cretaceous age.

On April 17, 2023, the Corporation completed the arm's length acquisition of certain low decline natural gas assets in the Southern Alberta Foothills ("Acquisition 2") of Acquisition 2 effective January 1, 2023. The assets acquired pursuant to Acquisition 2 are mostly late-life, Foothills Cretaceous age natural gas assets with current production of approximately [2.44] MMcf/d (or [406] BOE/d) and an estimated annual decline rate of [7]%. The assets also include approximately 8,331 gross (8,261 net) hectares. These lands are at the eastern edge of the Alberta Thrust Belt, and within the sweet shallow gas producing areas of southeastern Alberta. Also, included is a sweet gas plant with a nameplate capacity of 140 e³m³/d (approximately 5 MMcf/d).

On September 28, 2023, the Corporation executed a mining claims purchase and sale agreement (the "Cascade Agreement") to sell 90% of its interest in the Isintok property to Cascade Copper Corp. ("Cascade") (please see "Corporate History – Pre-Recapitalization" above for an overview of the Corporation's mineral claims). The transaction closed on October 13, 2023, and the purchase price of $200,000 was satisfied through the issuance of 2,150,583 units of Cascade at a deemed price of $0.093 per Cascade unit. Each Cascade unit was comprised of one (1) Cascade share and one-half of one (1/2) Cascade share purchase warrant. Each whole warrant is exercisable for one (1) Cascade share at an exercise price of $0.15 for a period of three years. The Corporation still retains 10% ownership in the Isintok property.

On December 28, 2023, the Corporation completed a brokered private placement (the "2023 Financing") for aggregate gross proceeds of approximately $1.6 million from the issuance of 31,938,299 units of the Corporation (the "Units") at a price of $0.05 per Unit. Each Unit was comprised

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of one (1) Common Share and one (1) Common Share purchase warrant (a “Financing Warrant”). Each Financing Warrant entitles the holder thereof to purchase one (1) Common Share at an exercise price of $0.075 per Common Share for a 36-month term ending December 28, 2026. In connection with the 2023 Financing, the Corporation also issued 1,398,400 broker warrants (“Broker Warrants”) to the agent under the 2023 Financing and certain other selling group firms in connection with the 2023 Financing. Each Broker Warrant entitles the holder thereof to purchase one (1) Unit at an exercise price equal to $0.05, and is exercisable any time prior to December 28, 2026. Each Unit is comprised of one (1) Common Share and one (1) Financing Warrant.

Financial Year Ended December 31, 2024

On May 13, 2024, the Corporation announced a $1,234,833.60 loan evidenced by an interest free, senior secured promissory note (the “Promissory Note”), from an arm’s length third party. The loan proceeds were used to fund a deposit with the Alberta Energy Regulator (“AER”), required as a condition of the licence transfers for certain asset acquisition transactions announced in Acquisition 2 and Acquisition 3. The Deposit amount is held by the AER in an interest-bearing trust account and may be returned to the Corporation in the future once applicable regulatory requirements have been met.

On May 28, 2024, the Corporation completed the arm’s length acquisition of certain light oil assets in Southern Alberta (“Acquisition 3”). The assets acquired pursuant to Acquisition 3 are comprised of wells that produce from Mississippian aged reservoirs and 29,685 gross (29,396 net) hectares of mineral rights. The lands are prospective for further light oil development and are near the previously announced foothills acquisitions.

On May 28, 2024, the Corporation completed a non-brokered private placement (the “Spring 2024 Financing”) for aggregate gross proceeds of approximately $1.35 million from the issuance of 26,950,000 units (“Spring 2024 Units”) of the Corporation at an issuance price of $0.05 per Spring 2024 Unit. Each Spring 2024 Unit is comprised of one (1) Common Share and one (1) Common Share purchase warrant (“Spring 2024 Warrant”). Each Spring 2024 Warrant entitles the holder thereof to purchase one (1) Common Share at an exercise price of $0.075 for a period of 36 months from its issuance. In connection with the Spring 2024 Financing, the Corporation issued 1,854,000 broker warrants (the “Spring 2024 Broker Warrants”) to the agent, with each Broker Warrant entitling the holder thereof to purchase one (1) Spring 2024 Unit at an exercise price equal to $0.05 for a period of 36 months ending May 28, 2027.

On July 17, 2024, the Corporation executed a farm-in arrangement with an arm’s-length private company. The arrangement allows Tuktu to farm-in on certain undeveloped rights in the Southern Alberta deep basin.

On November 21, 2024, the Corporation completed a “best efforts” prospectus offering (the “Fall 2024 Financing”) for aggregate gross proceeds of approximately $10.05 million from the issuance of 111,664,805 units (“Fall 2024 Units”) of the Corporation at an issuance price of $0.09 per Unit, including a partial exercise of the over-allotment option. Each Fall 2024 Unit is comprised of one (1) Common Share and one-half of one (1/2) Common Share purchase warrant (each whole Common Share purchase warrant, a “Fall 2024 Warrant”). Each Fall 2024 Warrant entitles the holder thereof to purchase one (1) Common Share at an exercise price of $0.13 for a period of 24 months from its issuance. The Corporation issued 6,033,221 broker warrants (the “Fall 2024 Broker Warrants”) to the agent, with each Fall 2024 Broker Warrant entitling the holder thereof to purchase one (1) Fall 2024 Unit at an exercise price equal to $0.09 for a period of 24 months ending November 21, 2026.

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Financial Year Ended December 31, 2025

On January 27, 2025, the Board approved a $6.85 million capital budget for H1 2025, allocated primarily to the drilling and completion of the Corporation's first horizontal well in the Monarch area, along with continued land acquisition and production optimization. On February 4, 2025, the Corporation announced the expansion of its land position by approximately 27.75 gross sections (approximately 18,096 acres), bringing its total prospective land holdings in the Monarch area to approximately 50 gross sections.

On February 4, 2025, the Corporation spud its first horizontal well (16-20) targeting the newly discovered Upper Banff reservoir in the Monarch area. Intermittent flow back commenced on March 7, 2025, with swab-assisted recovery over the following eleven days. The well was subsequently treated with a 20-stage, 370-ton crosslinked gelled water frac and equipped for production, as announced by the Corporation on March 24, 2025. The horizontal well did not achieve commercial production rates and was subsequently shut-in pending further evaluation.

On September 17, 2025, Kathleen Dixon, Chair of the Board, was appointed interim President and Chief Executive Officer, replacing Tim de Freitas. Gregory Feltham, Vice President, Exploration, and Kent Busby, Vice President, Production, also departed the Corporation on that date. The Board concurrently commenced a strategic review of the Corporation's operations and suspended the incremental capital budget that had been announced in August 2025.

On October 29, 2025, the Corporation appointed Jeremy Hodder as President and Chief Executive Officer. Mr. Hodder has over 25 years of experience in the Western Canadian oil and gas industry. Kathleen Dixon resumed her role as Chair of the Board.

Recent Events (Post Year-End)

2026 Corporate Strategy

On January 7, 2026, the Corporation announced its updated corporate strategy under new management. The strategy focuses on the Monarch (Banff) oil play as the Corporation's principal asset, with plans to conduct a detailed review and interpretation of existing 2D seismic data, acquire available 3D seismic data over the Corporation's land base, conduct core rock studies and petrophysical work to build a refined geological model of the Banff and Big Valley formations, and identify workover and recompletion candidates from existing wells. The Corporation also announced its intention to divest non-core assets (including the Eastern Alberta shallow gas properties and to evaluate strategic alternatives for its deep sweet/sour gas assets), reduce general and administrative expenses, reduce corporate asset retirement obligations in order to seek the release of all or a portion of its Alberta Energy Regulator security deposits, and evaluate assets that complement the Monarch asset base with a focus on oil and liquids-rich opportunities.

Special Meeting Results

On January 15, 2026, a special meeting of shareholders was held (the "Special Meeting") as requisitioned by a group of shareholders (the "Dissident Group") led by Jim Richardson and including Tim de Freitas to consider a resolution to remove all incumbent directors (other than Tim de Freitas) and replace them with a slate of nominees proposed by the Dissident Group. The resolution of the Dissident Group was defeated at the meeting, with approximately 59.4% of votes cast against the resolution. Additionally, shareholders voted to remove Tim de Freitas as a director of the Corporation, with approximately 59.7% of votes cast in favour of the Director Removal Resolution.

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Appointment of Chief Financial Officer and Management Departures

On February 13, 2026, the Corporation appointed Craig Wall, CPA, CA, as Chief Financial Officer. Mr. Wall is a Chartered Professional Accountant with experience in the oil and gas sector. On the same date, Mark Smith ceased serving as Chief Financial Officer and Sumir Saini ceased serving as Vice President, Land and Business Development.

Board Composition

Following the Special Meeting and subsequent management changes, the Board of Directors consists of Kathleen Dixon (Chair), Robert Dales, William (Bill) Guinan, Natalie Sweet, and Robert Yurchevich. Jeremy Hodder serves as President and Chief Executive Officer and Craig Wall serves as Chief Financial Officer.

Significant Acquisitions

During the financial year ended December 31, 2025, the Corporation did not complete any significant acquisitions or dispositions, or enter into any significant probable acquisitions, as such terms are defined in National Instrument 51-102 – Continuous Disclosure Obligations.

DESCRIPTION OF BUSINESS

General

Tuktu is an oil and natural gas development and production company headquartered in Calgary, Alberta. The Corporation's principal asset is the Monarch (Banff) oil play in the Southern Alberta Foothills. The Corporation also holds sweet natural gas assets in the southern foothills and Eastern Alberta, which the Corporation has identified as non-core and is evaluating for divestiture as part of its strategy announced in January 2026. See "Corporate History – Recent Events (Post Year-End)".

Business Plan

The Corporation's business plan, as announced on January 7, 2026, is focused on the following strategic objectives:

advancing its core Monarch oil play through a disciplined, data-driven approach to reservoir characterization and development;
improving well targeting and geological understanding through the interpretation of existing 2D seismic data and the potential acquisition of 3D seismic coverage over its land base;
conducting core rock analysis and petrophysical studies to support the development of a refined geological and depositional model of the Banff and Big Valley formations;
pursuing low-cost well workovers and recompletions of existing wells to de-risk the play, optimize production, and extend asset life;
identifying future drilling opportunities only where supported by robust technical validation, with an emphasis on capital efficiency and risk mitigation;
reducing general and administrative expenses and implementing measures to lower operating costs and improve overall financial performance;
evaluating the divestment of non-core assets to strengthen the Corporation's balance sheet and reallocate capital toward higher-return opportunities;
assessing strategic acquisition opportunities that complement the Monarch asset base, with a focus on oil and liquids-rich assets that are accretive and aligned with the Corporation's scale and expertise;

reducing corporate asset retirement obligations as part of broader balance sheet management;
broadening and enhancing internal policies, including those related to environmental, health and safety, ESG matters, and internal controls; and
fostering transparent and effective communication with internal stakeholders, the board of directors, and external partners.

Oil and Natural Gas Properties

The following is a description of our principal natural gas and oil properties as at December 31, 2025.

Map 1: foothills, deep basin and shallow gas assets in southern Alberta shown relative to primary Alberta roads, cities, and counties.

Monarch (formerly Penny)

The Monarch property is the Corporation's principal asset, located in Southern Alberta within the Southern Alberta Foothills fairway. Production is sourced from the Upper Banff Formation through vertical wells. In Q1 2025, the Corporation drilled its first horizontal well (16-20) targeting the Upper Banff reservoir. The horizontal well did not achieve commercial production rates and is currently shut-in pending further evaluation; as disclosed in the January 7, 2026 corporate strategy announcement, the well will likely remain shut-in indefinitely. The Corporation's land position in the Monarch area is approximately 50 gross sections. See "General Development of the Business – Fiscal Year 2025" for further details regarding the horizontal well program.

The gas/oil ratio of these wells is low, and all associated gas is flared. Producing units include the Big Valley and Exshaw formations and from Upper Banff zone, but the majority of the production is from the latter zone. Most of the lower formations (Big Valley and Exshaw) are produced through stage-fracture stimulated horizontal wellbores, while the Upper Banff reservoir is produced by a combination of vertical and horizontal well bores. Area production flows through to single or multiple well batteries and is trucked to third party facilities for sale. Under its 2026 corporate strategy, the Corporation intends to conduct a detailed seismic review of existing data across the Monarch area and to identify workover and recompletion candidates from existing wellbores prior to evaluating future drilling programs.

Tuktu Resources Ltd.
2026 Annual Information Form

Tuktu Resources Ltd.
2026 Annual Information Form
Page 13

Quaich

The Quaich assets occur within the southern Alberta Foothills. Two deviated wells produce sweet gas from Cretaceous formations and flow into a 100% owned and operated sweet gas plant. The associated sweet gas plant has a name plate capacity of 5 MMcf/d. This plant was built in 2006 and is within about 2 km of the Nova Gas Transmission Ltd. ("Nova Gas") sales gas line which benefits the Corporation due to low gas- transport costs. These gas wells produce from highly fractured Cretaceous reservoirs in the footwall of the Livingstone Thrust. The Livingstone Range, which is carried by this thrust fault, forms a prominent physiographic feature in the southern Alberta Foothills and Rockies.

Pincher Creek

The Corporation's Pincher Creek asset is in the frontal part of the Thrust Belt and within the "triangle zone", a structural geological feature bounded by detachments (faults) which occur typically at the transition from the foothills to the unstructured-to-mildly deformed deep basin. The light oil reservoirs being targeted by the Corporation are carried above a deep detachment below Devonian and Mississippian strata. The deeper Mississippian Pincher Creek field has produced more than 0.5 Tcf of sour, liquids-rich gas (based on GeoScout data) but it is currently shut in and mostly depleted. Due to the long production history of this field, the area has extensive gas-gathering lines and compression that are connected to the deep-cut, sour Waterton Gas Plant, operated by Pieridae Alberta Production Ltd. While deep reservoirs in this area are sour, shallower Cretaceous and Jurassic reservoirs contain sweet gas, light oil, and condensate.

The Corporation has identified certain operational challenges at the Pincher Creek property, including surface access constraints and a liability profile that management considers disproportionate to the property's current and anticipated production contribution. The Corporation is evaluating strategic alternatives for this property as part of its broader review of non-core assets.

Eastern Alberta

The Corporation's Eastern Alberta properties consist of shallow natural gas wells located across several areas in eastern Alberta. Production rates are relatively low on a per-well basis, and management has determined that these assets are uneconomic in low commodity price environments. The Corporation intends to divest its Eastern Alberta shallow gas assets as part of its strategy to focus on its core Monarch property.

Tuktu Resources Ltd.
2026 Annual Information Form

Mineral Properties

As of December 31, 2025, the Corporation had interests in two mineral properties located in British Columbia.

Map 2: 2024 existing and relinquished claims within the province of British Columbia, Ruddock Creek in a non-operating property with a net smelter Royalty of 1.5% payable to Tuktu. Tuktu also has a 10% non-operating working interest in Plateau Mountain, and the majority interest was sold to Cascade Copper Corp.

Ruddock Creek (Irony)

The Irony property was sold to Selkirk Metals in 2014, but the Corporation retained a Net Smelter Royalty of 1.5%. These claims are in good standing until December 2030. The Irony claim is underlain by polydeformed Proterozoic metasediments containing several high-grade mineralization zones. Selkirk Metals compiled an NI 43-101 report (R.G. Simpson and J. Miller, 2012; this and all associated reports are available from (British Columbia Mining). In the NI 43-101 report, the authors reported significant tonnage of inferred and indicated resources (Zn and Pb). The authors described tabular, syndepositional bodies that host, at a 4% Pb/Zn grade cutoff, an Indicated Resources of 2.338 million tons of 7.79% Zn and 1.61% Pb and an Inferred Resource of 1.492 million tons of 6.5% Zn and 1.26% Pb. As at March 2024, the operator of the claim (Selkirk Metals) does not anticipate commencement of mining operations within the next 24 months.

Isintok (Copper Plateau)

The Isintok property, near Summerland BC is one of many Cretaceous copper porphyry deposits in BC. The showing is similar in grade and genesis to the nearby Brenda Mine. Drilling of these deposits indicated significant mineralized intersections that will require additional exploratory drilling. In July 2011, AMC Consultants (BC Assessment report 767129, which is not NI 43-101 compliant) reported 50,000,000 to 110,000,000 tonnes of 0.08-0.12% Cu, 0.01-0.02% Mo, 0.02-0.03 g/t Au, and 0.08 to 1.10 g/t Ag. Cascade Copper Corporation (CSE: CASC) expressed interest in acquiring this property, and, as such, on September 28, 2023, Tuktu entered the Cascade Agreement to sell these assets. As part of the sales agreement, Tuktu retained a 10% working interest in the property. For more

Page 14

information (including in respect of purchase consideration), please see "Corporate History – Financial Year ended December 31, 2023".

Other Business information

Tuktu employs individuals with various professional skills in the course of pursuing its business plan. These professional skills include, but are not limited to, geology, geophysics, engineering, marketing, legal, capital markets, business development, finance and other business skills. Following the management transition in the second half of 2025 and early 2026, the Corporation's management team, led by President and Chief Executive Officer Jeremy Hodder and Chief Financial Officer Craig Wall, is focused on advancing the Corporation's Monarch oil play through a disciplined, data-driven approach. See "Directors and Officers" and "Corporate History – Recent Events (Post Year-End)" for further details regarding the Corporation's current management team.

Employees

As at December 31, 2025, the Corporation had two employees. See "General Development of the Business – Fiscal Year 2025" and "Recent Events (Post Year-End)" for a description of changes in the Corporation's management team during 2025 and early 2026.

Competitive Conditions

The oil and natural gas industry is intensely competitive, and Tuktu competes with a substantial number of other entities, many of which have greater technical, operational and/or financial resources. With the maturing nature of the Western Canadian Sedimentary Basin, the access to new prospects is becoming more competitive and complex. Tuktu attempts to enhance its competitive position by operating in areas where it believes its technical personnel are able to reduce some of the risks associated with exploration, production and marketing because the Corporation has established core competencies in these areas of operation, particularly in the Alberta and British Columbia Foothills. Management believes that Tuktu will be able to explore for and develop new production and reserves with the objective of increasing its adjusted funds flow and reserve base.

Commodity Price Cycles

The Corporation's operational results and financial condition are dependent on commodity prices, specifically the prices of oil, natural gas, NGL and seasonal and regional market price spreads. Commodity prices have fluctuated widely during recent years and are determined by supply and demand factors including general economic conditions, weather, environmental regulations and policies, geopolitical risks, oil and gas resource extraction technologies, oil fields equipment and services, local and regional access to markets, refining capacity, as well as operating results and conditions in other oil and natural gas producing regions.

Environmental Protection

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Compliance with such legislation may require significant expenditures or result in operational restrictions. Breach of such requirements may result in suspension or revocation of necessary licences and authorizations, civil liability for pollution damage and the imposition of material fines and penalties, all of which might have a significant negative impact on earnings and overall competitiveness of the Corporation. For a description of the financial and operational effects of environmental protection requirements on the capital expenditures, earnings and competitive position of Tuktu see "Industry Conditions – Environmental Regulation" and "Risk Factors – Environmental".

Tuktu Resources Ltd.
2026 Annual Information Form

Economic Dependence

The Corporation has ensured economic diversity by not being substantially dependent on any single contract or license, such as a contract to sell the major part of its products or services or to purchase the majority of its goods, services or raw materials, or any franchise, license or other agreement to use a patent, formula, trade secret, process or trade name upon which Tuktu's business depends.

Changes to Contracts

The Corporation does not reasonably anticipate being materially affected by renegotiation or termination of contracts or sub-contracts.

Environmental, Social and Governance ("ESG")

Tuktu is committed to strong ESG performance across all aspects of its operations. Key factors of the Corporation's ESG program include emissions management and minimizing our environmental footprint. In addition, Tuktu places a high priority on fostering positive relationships with our stakeholders and the communities in which we operate. The Corporation is committed to upholding the highest standards of social responsibility, including respect for human rights, labor rights, and community engagement. In addition, the Corporation remains committed to ensuring that its governance practices are in line with best practices, taking into consideration both industry standards and Tuktu's size and stage of development.

Environmental, Health and Safety Policies

The Corporation supports environmental protection and worker health and safety through the implementation and communication of the Corporation's environmental management and health and safety policies, practices, and procedures. Committees focused on environment, health, and safety ("EH&S") issues are established in the Corporation's operations which are designed to drive continuous improvement in policies, practices and procedures which drive accountability for EH&S by the Corporation and its employees. Practices for continuous improvement of EH&S performance management includes providing employees with job orientation, training, instruction, systems and supervision and incident reviews to build competency, skill, and accountability in conducting daily activities in a healthy, environmentally responsible, and safe manner.

The Corporation develops emergency response practices, procedures, and readiness plans in conjunction with local authorities, emergency services and the communities in which it operates to effectively respond to an environmental or safety incident should it arise. The effectiveness of these plans is evaluated on a regular basis to ensure preparedness for emergency situations. Environmental and risk assessments are undertaken for new projects, or when acquiring new properties or facilities in order to identify, assess and minimize environmental risks, loss and operational exposures. The Corporation conducts reviews of operations to measure compliance with internal and industry standards, and for continuous improvement in practices and procedures. Documentation is maintained to support internal accountability and measure operational performance against recognized industry and proactive leading indicators to assist in achieving the objectives of the described policies and programs.

The Corporation also faces environmental, health and safety risks in the normal course of its operations due to the handling and storage of hazardous substances. The Corporation's environmental and health and safety management systems are designed to manage such risks in the Corporation's business and allow action to be taken to control the risk of environmental, health or safety impacts from such operations. A key aspect of these systems is the conducting of internal and external inspection and audits of worksites and offices.

Tuktu Resources Ltd.
2026 Annual Information Form

Tuktu Resources Ltd.
2026 Annual Information Form
Page 17

Elements of our Environmental, Health and Safety Management System

System Monitoring

The Corporation defines EH&S performance and identifies action for improvement through measurement and analysis. Tuktu had no reportable spills, zero injuries and zero vehicle incidents in 2025. Continued focus on HSE training has resulted in improved safety performance.

Training and Competency

The Corporation ensures that employees and contractors have the necessary skills to work properly, safely and protect the environment. Safety certification is important not only from a regulatory perspective, but also from the confidence it gives a worker to do the job correctly and safely. Competency is the key; that is adequately qualified, suitably trained and sufficiently experienced to do the job without supervision. Site specific training is key in incident prevention as each situation has its unique set of hazards that need to be controlled, and uses skilled worker experience and mentoring. Regular safety meetings provide a venue to review incidents, provide training, management direction, critical information and promote two-way communication.

Hazard Assessment

The Corporation identifies items and tasks that have the potential to cause loss or injury and encourages employees to actively identify hazards they recognize and put forth recommendations to reduce risks and eliminate hazards. Hazard reporting is a valuable leading indicator, as it identifies hazards, levels of risk and controls required to do a job safely and efficiently. All hazards are followed up for proper corrective actions.

Risk Management

The Corporation has an inspection and audit program to provide feedback and action items to ensure success, identify hazards and controls, and continuous improvement. Risk assessments are critical, as a hazard by itself cannot hurt you without the risk of exposure. Tuktu has an ongoing Asset Integrity program which includes our Pipeline Integrity Manual, Pipeline Operations Manual, Electrical Quality Management Plan and Pressure Equipment Integrity Program.

Incident Reporting and Investigation

The Corporation has an incident reporting and tracking program which helps to identify training needs and work practice/procedure issues, as well as identifies potential gaps in the safety management system. It is through the identification and correction of root cause that real change can occur to prevent further loss.

Policy and Management Involvement

The Corporation's EH&S policies clearly articulate the EH&S Vision of Tuktu and provides the tools to promote and enforce an incident free workplace and demonstrates management's leadership in the safety program. They establish responsibilities at each level. Company policies are senior management's way to endorse and communicate their desire and commitment to being a safety leader thus encouraging positive behavior. The guiding principles give employees the framework to develop their behavior around what the Corporation expects for safety. These responsibilities are critical for creating accountabilities and reaching the Corporation's goals.

Tuktu Resources Ltd.
2026 Annual Information Form
Page 18

Emergency Response Management

The Corporation develops, maintains, and tests emergency response plans to ensure a safe, prompt and effective response to emergencies, in order to minimize any adverse environmental and other impacts.

Air

The Corporation tracks direct and indirect greenhouse gas ("GHG") emissions, flared and vented gas volumes and fugitive emissions and continuously works to reduce air emissions in conjunction with industry best practices and regulations. Tuktu actively monitors fugitive emissions at all operated wells, pipelines, and facilities in accordance with provincial regulations. Tuktu maintains a Methane Reduction Retrofit Compliance Plan designed to lower methane emissions in accordance with Directive 60 of the Alberta Energy Regulator.

Water

The Corporation strives to minimize fresh water usage in all of its operations. To date, there are no material impacts to area surface or subsurface water. Produced water is only in our foothills gas wells: it is near- potable and disposed of, as per industry regulations.

Land and Reclamation

The Corporation employs environmental management best practices along with proactive strategies that minimize our impact associated with full cycle environmental alteration and reclamation. Understanding as a tenant of the land, we intend to consciously comply with regulations and employ efficient and proactive strategies to conserve and protect from adverse environmental impact or loss including reducing freshwater use through innovative technologies to recycle and reuse where possible. The Corporation promotes proper waste management, safe handling, use and disposal of chemicals and lubricants, as well as the handling, storage and transportation of our products. Tuktu's intent is to reclaim sites under a robust reclamation process such that each site is restored to its original state.

Reorganizations

There have been no material corporate reorganizations of the Corporation during the three most recently completed financial years.

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The reserves data set forth below is based upon the figures contained in the report of Deloitte Canada LLP ("Deloitte") dated effective December 31, 2025, with a preparation date of April 1, 2026 (the "Deloitte Report") evaluating substantially all of Tuktu's assets.

Disclosure of Reserves Data

The Report on Reserves Data by Deloitte in Form 51-101F2 is attached as Appendix A to this Annual Information Form and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 is attached as Appendix B to this Annual Information Form.

In the Deloitte Report, Deloitte evaluated 100% of the assigned total proved plus probable reserves. Deloitte prepared their reserve report using their own technical assumptions and interpretations,

methodologies and cost assumptions of Deloitte. Due to rounding, certain columns set forth below in this section may not add.

The Deloitte Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101, CSA 51-324, and the COGE Handbook. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which Tuktu believes is important to readers of this Annual Information Form. Deloitte was engaged to provide evaluations of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves. All the Corporation's reserves are in the province of Alberta.

There are numerous uncertainties inherent in estimating quantities of crude oil, NGL and conventional natural gas reserves and the future cash flows attributed to such reserves. The reserves and associated cash flow information set forth in this Annual Information Form are estimates only. In general, estimates of economically recoverable crude oil, NGL and conventional natural gas reserves and the future net revenues therefrom are based upon a number of variable factors and assumptions, such as geological, geophysical, and engineering assessment of hydrocarbons in place on Company lands, historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital and abandonment and reclamation 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 from actual results. For those reasons, estimates of the economically recoverable crude oil, NGL and conventional 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. The Corporation's actual production, revenues, royalties, development, abandonment and reclamation, and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

The information relating to the Tuktu's crude oil, NGL and conventional natural gas reserves contains forward-looking statements relating to anticipated production, future net revenues, forecast capital expenditures, future development plans and costs related thereto, forecast operating costs, anticipated production, and abandonment and reclamation costs.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained, and variances could be material. Actual reserves and value may be greater, or less, than the estimates provided in this Statement of Reserves and Other Oil and Gas Information.

SUMMARY OF OIL AND GAS RESERVES
As at December 31, 2025 (Forecast Costs and Prices) $^{(1)}$

Company Reserves
Total Company	Tight Oil (Mbbl)		Light and Medium Oil (Mbbl)		Conventional Natural Gas (MMcf)		Total Oil Equivalent (Mboe)
Reserves Category	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Proved Developed Producing	178.8	156.6	0.0	0.0	4,397.6	3,867.9	911.7	801.2
Proved Developed Non-Producing	28.7	25.1	0.0	0.0	0.0	0.0	27.8	25.1
Proved Undeveloped	249.9	220.2	0.0	0.0	0.0	0.0	249.9	220.2
Total Proved	456.6	401.8	0.0	0.0	4,397.6	3,867.9	1,189.5	1,046.4
Probable	2,826.8	2,408.2	118.5	109.9	3,500.3	2,908.1	3,528.7	3,002.8
Total Proved Plus Probable	3,283.4	2,810.0	118.5	109.9	7,897.9	6,776.0	4,718.2	4,049.2

Tuktu Resources Ltd.
2026 Annual Information Form

Note:
(1) Gross refers to company interest before royalties. Net refers to volumes after royalties.

NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR)
BEFORE TAX as at December 31, 2025 (Forecast Costs and Prices)(1,2)

Net Present Value of Future Net Revenue
Total Company	Before Income Taxes, Discounted at (% / year)					Unit Value Before Income Tax, Discounted at 10% / year
Reserves Category	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)	$/boe	$/Mcfe
Proved Developed Producing	8,324.7	7,664.3	6,908.6	6,251.2	5,707.9	7.58	1.26
Proved Developed Non-Producing	596.2	546.6	490.5	438.5	393.5	17.58	2.93
Proved Undeveloped	7,348.3	5,725.7	4,583.6	3,746.6	3,111.1	18.34	3.06
Total Proved	16,269.2	13,936.6	11,982.7	10,436.3	9,212.5	10.07	1.68
Probable	107,344.1	74,669.0	55,279.7	42,413.3	33,358.2	15.67	2.61
Total Proved Plus Probable	123,613.3	88,605.5	67,262.4	52,849.7	42,570.6	14.26	2.38

Notes:
(1) Barrel of Oil Equivalent (BOE): 6 Mcf = 1 BOE
(2) Unit Values in $C are based on net reserve volumes

NET PRESENT VALUES OF FUTURE NET REVENUE
AFTER INCOME TAXES DISCOUNTED AT (%/YEAR)
AFTER TAX as at December 31, 2025 (Forecast Costs and Prices)(1,2)

Net Present Value of Future Net Revenue
Total Company	After Income Taxes, Discounted at (% / year)					Unit Value After Income Tax, Discounted at 10% / year
Reserves Category	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)	$/boe	$/Mcfe
Proved Developed Producing	8,324.7	7,664.3	6,908.6	6,251.2	5,707.9	7.58	1.26
Proved Developed Non-Producing	596.2	546.6	490.5	438.5	393.5	17.58	2.93
Proved Undeveloped	7,348.3	5,725.7	4,583.6	3,746.6	3,111.1	18.34	3.06
Total Proved	16,269.2	13,936.6	11,982.7	10,436.3	9,212.5	10.07	1.68
Probable	84,282.9	57,643.8	42,012.4	31,710.6	24,514.7	11.90	1.98
Total Proved Plus Probable	100,552.1	71,580.3	53,995.0	42,146.9	33,727.1	11.44	1.91

Notes:
(1) Barrel of Oil Equivalent (BOE): 6 Mcf = 1 BOE
(2) Unit Values in $C are based on net reserve volumes

Tuktu Resources Ltd.
2026 Annual Information Form

FUTURE NET REVENUE (UNDISCOUNTED)
(as at December 31, 2025 Forecast Prices and Costs)(1)

Reserves Category	Company Revenue	Royalties	Operating Costs	Investment Costs	Well Abandonment Costs	Future Net Revenue	Income Tax	Future Net Revenue After Income Tax (M$)
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Proved Developed Producing	32,802.4	3,251.2	18,496.9	0.0	2,729.6	8,324.7	0.0	8,324.7
Proved Developed Non-Producing	2,332.6	231.9	1,360.4	0.0	144.0	596.2	0.0	596.2
Proved Undeveloped	20,290.4	2,461.2	4,920.7	5,393.5	166.7	7,348.3	0.0	7,348.3
Total Proved	55,425.3	5,944.3	24,778.1	5,393.5	3,040.3	16,269.2	0.0	16,269.2
Probable	282,801.6	41,550.1	78,469.7	53,231.2	2,206.6	107,344.1	23,061.1	84,282.9
Total Proved Plus Probable	338,226.9	47,494.4	103,247.8	58,624.6	5,246.8	123,613.3	23,061.1	100,552.1

Note:
(1) Revenue includes product revenue and other income from facilities, wells and corporate if specified.

FUTURE NET REVENUE BY PRODUCT TYPE
(as at December 31, 2025)(1,2)

Reserves Category	Production Group	Future Net Revenue Before Income Tax, Discounted at 10%/Year	Unit Value Before Income Tax, Discounted at 10%/Year
		(M$)	($/Boe, $/Mcf))
Total Proved
	Tight Oil	7,484.1	16.39
	Light / Medium Oil	0.0	0.00
	Conventional Natural Gas	4,498.	6.14
Total: Total Proved		11,982.6	10.07

FUTURE NET REVENUE BY PRODUCT TYPE
(as at December 31, 2025)(1,2)

Reserves Category	Production Group	Future Net Revenue Before Income Tax, Discounted at 10%/Year (M$)	Unit Value Before Income Tax, Discounted at 10%/Year ($/Boe, $/Mcf))
Total Proved Plus Probable
	Tight Oil	59,835.3	18.22
	Light / Medium Oil	1,630.9	13.76
	Conventional Natural Gas	5,796.2	4.40
Total: Total Proved Plus Probable		67,262.4	14.26

Notes:
(1) Unit values are calculated using the future net revenue discounted at 10% divided by the major production type net reserves for each group.
(2) Barrel of Oil Equivalent (BOE): 6 Mcf = 1 BOE

Tuktu Resources Ltd.
2026 Annual Information Form

Reconciliation of Company Gross Reserves by Product Type(1,2)
(as at December 31, 2025)

The following table sets forth a reconciliation of the changes in the Corporation's gross reserves as at December 31, 2025, against the Corporation's reserves as at December 31, 2024, based on the forecast price and cost assumptions evaluated in accordance with NI 51-101 definitions:

Total Company	Tight Oil			Light / Medium Oil			Conventional Natural Gas			Total BOE
Factors	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
December 31, 2024	580.9	2,846.5	3,427.4	0.4	114.3	114.7	4,836.0	3,396.1	8,232.1	1,387.3	3,526.8	4,914.1
Production	-95.4	0.0	-95.4	-0.2	0.0	-0.2	-673.2	0.0	-673.2	-207.8	0.0	-207.8
Technical Revisions	-303.2	-339.8	-643.0	0.0	4.6	4.6	251.4	115.3	366.7	-261.3	-316.0	-577.3
Extensions and Improved Recovery	0.0	599.8	599.8	0.0	0.0	0.0	0.0	0.0	0.0	0.0	599.8	599.8
Discoveries	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Acquisitions	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Dispositions	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Economic Factors	-3.5	-1.9	-5.4	-0.2	-0.3	-0.6	-16.6	-11.1	-27.7	-6.5	-4.1	-10.6
December 31, 2025	178.8	3,104.6	3,283.4	0.0	118.5	118.5	4,397.6	3,500.3	7,897.9	911.7	3,806.5	4,718.2

Notes:
(1) Reserves for the previous year were not held by the corporation
(2) Gross refers to company interest before royalties

Forecast Prices and Costs

The following prices and other values were provided by Deloitte.

NI 51-101
Summary of Pricing and Inflation Rate Assumptions (as of December 31, 2025)
Forecast Prices and Costs

Year	WTI Cushing Oklahoma ($US/bbl)	Alberta AECO-C Spot ($Con/mcf)	Edmonton Pentanes Plus ($Con/bbl)	Edmonton Butane ($Con/bbl)	Edmonton Propane ($Con/bbl)	Operating Cost Inflation Rate (%Yr)	Capital Cost Inflation Rate (%Yr)	Exchange Rate ($US/$Con)
Forecast
2026	58.00	$2.95	$74.65	$33.60	$26.15	0	0	0.73
2027	61.20	$3.55	$76.50	$34.45	$26.80	2	2	0.75
2028	67.65	$3.65	$84.65	$38.10	$26.60	2	2	0.75
2029	69.00	$3.70	$86.35	$38.85	$30.20	2	2	0.75
2030	70.35	$3.80	$88.05	$39.60	$30.80	2	2	0.75
2031	71.75	$3.85	$89.80	$40.40	$31.40	2	2	0.75
2032	73.20	$3.95	$91.60	$41.20	$32.05	2	2	0.75
2033	74.65	$4.00	$93.45	$42.05	$32.70	2	2	0.75
2034	76.15	$4.10	$95.30	$42.90	$33.35	2	2	0.75
2035	77.70	$4.20	$97.20	$43.75	$34.00	2	2	0.75
Escalation Rate of 2.0% thereafter

Tuktu Resources Ltd.
2026 Annual Information Form

Proved Undeveloped Reserves

The following table discloses, for each product type, the volumes of proved undeveloped reserves that were first attributed in each of the most recent three financial years and, in the aggregate, before that time.

SUMMARY OF PROVED UNDEVELOPED RESERVES

(as at December 31, 2025, Forecast Prices & Costs)

Company Gross Reserves
	Tight Oil (Mbbl)		Light and Medium Oil (Mbbl)		Conventional Natural Gas (MMcf)		Total Oil Equivalent (Mboe)
Year	First Attributed	Current Total	First Attributed	Current Total	First Attributed	Current Total	First Attributed	Current Total
December 31, 2023	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
December 31, 2024	249.9	249.9	0.0	0.0	0.0	0.0	249.9	249.9
December 31, 2025	0.0	249.9	0.0	0.0	0.0	0.0	249.9	249.9

Probable Undeveloped Reserves

The following table discloses, for each product type, the volumes of probable undeveloped reserves that were first attributed in each of the most recent three financial years and, in the aggregate, before that time.

SUMMARY OF PROBABLE UNDEVELOPED RESERVES

(as at December 31, 2025, Forecast Prices & Costs)

Company Gross Reserves
	Tight Oil (Mbbl)		Light and Medium Oil (Mbbl)		Conventional Natural Gas (MMcf)		Total Oil Equivalent (Mboe)
Year	First Attributed	Current Total	First Attributed	Current Total	First Attributed	Current Total	First Attributed	Current Total
December 31, 2023	0.0	0.0	0.0	123.5	0.0	0.0	123.5	123.5
December 31, 2024	3,080.0	3,080.0	123.5	114.3	0.0	0.0	3,203.5	3,194.3
December 31, 2025	599.8	2,998.8	0.0	114.3	0.0	0.0	599.8	3,113.1

Future Development Costs

The following table sets forth development costs deducted in the estimation of Tuktu's future net revenue.

Future Development Costs

Estimated Using Forecast Prices and Costs (Undiscounted)

Year
Reserves Category	2026 (M$)	2027 (M$)	2028 (M$)	2029 (M$)	2030 (M$)
Proved Developed Producing	0.0	0.0	0.0	0.0	0.0
Proved Developed Non-Producing	0.0	0.0	0.0	0.0	0.0
Proved Undeveloped	0.0	5,393.5	0.0	0.0	0.0
Total Proved	0.0	5,393.5	0.0	0.0	0.0
Probable	0.0	10,876.2	19,759.8	22,547.6	0.0
Total Proved Plus Probable	0.0	16,269.7	19,759.8	22,547.6	0.0

Page 23

The Corporation expects to fund future development costs ("FDC") from internally-generated adjusted funds flow, debt or equity financing through the capital markets, or through joint venture arrangements with industry partners. The Corporation does not expect such costs to make development of any properties uneconomic. The Deloitte Report on Reserves Data estimates that FDC of $58.6 million will be required over the life of the Corporation's proved plus probable reserves. On a proved basis the Corporation anticipates spending $5.4 million.

As the Corporation continues to invest capital to bring on additional production, development of the undeveloped reserves will systematically be undertaken over the next several years.

Abandonment and Retirement Obligations

Deloitte's reserve assessment includes an estimate of the Corporation's total future decommissioning obligations based on net ownership interest in all wells, facilities and pipelines, including estimated costs to abandon the wells, facilities and pipelines and reclaim the sites, and the estimated timing of the costs to be incurred in future periods as summarized in the following table as at December 31, 2025.

Year(1)	Proved Developed Producing (M$)	Total Proved (M$)	Total Proved Plus Probable (M$)
2026	0.0	0.0	0.0
2027	0.0	0.0	0.0
2028	0.0	0.0	0.0
2029	229.6	229.6	231.9
2030	0.0	0.0	0.0
2031	240.9	240.9	0.0
2032	244.3	244.3	244.7
2033	250.0	250.0	123.9
2034	127.2	127.2	254.2
2035	0.0	0.0	128.9
2036	369.7	369.7	133.0
Remainder	1,268.9	1,411.9	4,130.2
Total(1)	2,729.6	2,873.5	5,246.8

Note:
(1) Est. internally in accordance with NI 51-101. Includes est. abandonment and reclamation for wells and facilities with no assigned reserves

Significant Factors and Uncertainties

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices, and economic conditions.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions, and government restrictions.

Tuktu Resources Ltd.
2026 Annual Information Form

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological, geophysical or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices and reservoir performance. Such revisions can be either positive or negative.

Other Oil and Gas Information

Oil and Gas Properties

A description of Tuktu's important oil and natural gas properties as at December 31, 2025 is included as part of "Description of the Business – Operations".

Oil and Gas Wells

The following table sets forth the number and status of wells in which the Corporation had a working interest as at December 31, 2025.

Property	Producing Gas Wells		Producing Oil Wells		Non-Producing Gas Wells		Non-producing Oil Wells
	Gross(1)	Net(2)	Gross	Net	Gross	Net	Gross	Net
Pincher Creek	0.0	0.0	0.0	0.0	1.0	0.7	1.0	1.0
Quaich	2.0	2.0	0.0	0.0	1.0	0.3	0.0	0.0
Eastern Alberta	18.0	18.0	0.0	0.0	72.0	72.9	0.0	0.0
Monarch	0.0	0.0	18.0	17.8	0.0	0.0	7.0	7.0

Notes:
(1) "Gross" - number of wells in which a working interest is held by the Corporation.
(2) "Net" -obtained by multiplying well count percentage working interest.

Acreage Information

The following table sets out Tuktu's developed and undeveloped land holdings as at December 31, 2025.

	Developed Acres		Undeveloped Acres		Total Acres
Property(1,2)	Gross	Net	Gross	Net	Gross	Net
Pincher Creek	800	744	5,906	4,811	6,706	5,555
Quaich	1,920	1,493	0	0	1,920	1,493
Eastern Alberta	17,604	17,431	1,760	1,760	19,364	19,191
Monarch	8,422	7,966	48,995	44,059	57,418	52,026

Notes:
(1) "Gross" means the total number of acres in which the Corporation has an interest
(2) "Net" derived by multiplying gross by working interest

Production Estimates

The following table sets out the volume of Tuktu's future production of 411 Boe/d estimated by Deloitte on a proved plus probable basis for the year ended December 31, 2025, which is reflected in the estimate of future net revenue disclosed in the tables.

Tuktu Resources Ltd.
2026 Annual Information Form

| 2026 Deloitte Forecast | Lt and Med Oil
bbl/d | Natural Gas
Mcf/d | TTL
Boe/d |
| --- | --- | --- | --- |
| Proved | 130 | 1,613 | 399 |
| Probable | 10 | 12 | 12 |
| Total proved plus probable | 140 | 1,625 | 411 |

Production History

The following tables summarize certain information in respect of production, product prices received, royalties paid, production and operating expenses, transportation and resulting netback for the periods indicated below.

Production	2025 Quarter ended
	Dec 31	Sept 30	June 30	March 31
Average daily conventional natural gas (mcf/d)	1,742	1,408	1,943	2,081
Average daily light oil (bbl/d)	187	215	298	358
TTL BOE/d (1)	477	450	622	705
Average Realized natural gas prices ($/Mcf)	2.41	0.94	1.79	2.21
Average realized oil prices ($/bbl)	71.13	79.51	78.23	88.77
Average Total realized prices ($/Boe) (1)	36.67	40.97	43.09	51.62
Royalties ($/Boe) (1)	(7.44)	(11.07)	(11.95)	(16.20)
Production and operating costs ($/Boe) (1)	(23.53)	(30.33)	(20.79)	(20.70)
Transportation costs ($/Boe) (1)	(0.80)	(0.64)	(0.69)	(1.37)
Operating netback ($/Boe) (1)	4.90	(1.07)	9.66	13.35

Note:
(1) Non-GAAP ratio. Refer to the section entitled “Non-GAAP and Financial Measures” contained in the 2025 MD&A for an explanation of composition.

The following table indicates Tuktu's average daily production from each of the Corporation's core areas for the year ended December 31, 2025.

| Property | Average annual daily production
(Boe/d) |
| --- | --- |
| Pincher Creek | 1 |
| Eastern Alberta | 34 |
| Quaich | 265 |
| Monarch (1) | 263 |
| Total | 563 |

Note:
(1) Oil production from Monarch (formerly Penny) commenced on May 27, 2024.

Capital Expenditures

Capital was deployed to acquire certain oil and gas properties. See “Oil and Gas Properties”.

Exploration and Development Activities

The Corporation recompleted bypass pay in a standing oil well within the Monarch asset resulting in a new pool discovery within the Upper Banff Formation. Subsequent to the completion operations, the well was equipped and initiated production in August 2024.

Tuktu Resources Ltd.
2026 Annual Information Form

Tuktu Resources Ltd.
2026 Annual Information Form
Page 27

Commodity Price Risk Management

Tuktu's commodity price risk management strategy is focused on market diversification, managing downside risk and increasing certainty in adjusted funds flow from operating and acquisition activities to ensure we are achieving an adequate return on invested capital by mitigating the effect of commodity price volatility. The Corporation does not currently have access to financial derivatives, but can employ physical delivery contracts to manage commodity price risk. Such sales agreements could be put in place to manage fluctuations in commodity prices, protecting Tuktu's cash flows from potential volatility.

DIVIDENDS

The Corporation has not declared or paid any dividends for each of the three most recently completed financial years. It is the intention of the Corporation to retain any earnings to finance the growth and development of the Corporation's business, and, therefore the Corporation does not anticipate paying any dividends in the immediate or foreseeable future.

DESCRIPTION OF CAPITAL STRUCTURE

The authorized share capital of Tuktu consists of an unlimited number of Common Shares and an unlimited number of preferred shares of the Corporation ("Preferred Shares"), issuable in series. As at the date hereof, there are 265,563,547 Common Shares and nil Preferred Shares issued and outstanding.

Common Shares

Each Common Share entitles the holder thereof to receive notice of and to attend all meetings of Shareholders of Tuktu and to one (1) vote per Common Share at such meetings. The Common Shares entitle the holders thereof to receive dividends, as and when declared by the Board, on the Common Shares as a class, subject to prior satisfaction of all preferential rights to dividends attached to all shares of other classes of shares of Tuktu ranking in priority to the Common Shares in respect of dividends. Holders of Common Shares will be entitled in the event of any liquidation, dissolution or winding-up of Tuktu, whether voluntary or involuntary, or any other distribution of the assets of Tuktu among its shareholders for the purposes of winding-up its affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of shares of Tuktu ranking in priority to the Common Shares in respect of return of capital on dissolution, to share rateably, together with the holders of shares of any other class of shares of Tuktu ranking equally with the Common Shares in respect of return of capital, in such assets of Tuktu as are available for distribution.

Preferred Shares

Preferred Shares may be issuable in one or more series, each series consists of such number of shares as may, before the issuance thereof, be determined by the Board. The Board may from time to time fix, before issuance, the designation, rights, privileges, restrictions and conditions attaching to each series of Preferred Shares including, without limiting the generality of the foregoing, the amount, if any, specified as being payable preferentially to such series on a distribution, the extent, if any, of further participation on a distribution, voting rights, if any, and dividend rights (including whether such dividends be preferential, or cumulative or non-cumulative), if any.

Tuktu Resources Ltd.
2026 Annual Information Form

Financing Warrants

On December 28, 2023, in connection with the 2023 Financing, the Corporation issued 31,938,299 Warrants (including 2,338,300 Warrants which were issued to the agent as partial commission for the financing). Each Warrant is exercisable for one (1) Common Share at an exercise price of $0.075 per Common Share, and is exercisable any time prior to December 28, 2026. For more information, please see "Corporate History – Financial Year ended December 31, 2023".

On May 28, 2024, in connection with the Spring 2024 Financing, the Corporation issued 27,950,000 Warrants (including 1,000,000 Spring 2024 Warrants which were issued to the agent as partial commission for the financing). Each Spring 2024 Warrant is exercisable for one (1) Common Share at an exercise price of $0.075 per Common Share, and is exercisable any time prior to May 28, 2027. For more information, please see "Corporate History – Financial Year ended December 31, 2024".

On November 21, 2024, in connection with the Fall 2024 Financing, the Corporation issued 55,832,402 Warrants. Each Fall 2024 Warrant is exercisable for one (1) Common Share at an exercise price of $0.13 per Common Share, and is exercisable any time prior to November 21, 2026. For more information, please see "Corporate History – Financial Year ended December 31, 2024".

Broker Warrants

On December 28, 2023, the Corporation also issued 1,398,400 Broker Warrants to the agent under the 2023 Financing and certain other selling group firms in connection with the 2023 Financing. Each Broker Warrant entitles the holder thereof to purchase one Unit at an exercise price equal to $0.05, and is exercisable any time prior to December 28, 2026. Each Unit is comprised of one (1) Common Share and one (1) Warrant. For more information, please see "Corporate History – Financial Year ended December 31, 2023".

On May 28, 2024, the Corporation also issued 1,854,000 Spring 2024 Broker Warrants to the agent under the Spring 2024 Financing and certain other selling group firms in connection with the Spring 2024 Financing. Each Spring 2024 Broker Warrant entitles the Agent to purchase one (1) Spring 2024 Unit at an exercise price equal to $0.05 anytime on or prior to May 28, 2027. For more information, please see "Corporate History – Financial Year ended December 31, 2024".

On November 21, 2024, the Corporation also issued 6,033,221 Fall 2024 Broker Warrants to the agent under the Fall 2024 Financing and certain other selling group firms in connection with the Fall 2024 Financing. Each Fall 2024 Broker Warrant entitles the Agent to purchase one (1) Fall 2024 Unit at an exercise price equal to $0.09 anytime on or prior to November 21, 2026. For more information, please see "Corporate History – Financial Year ended December 31, 2024".

MARKET FOR SECURITIES AND TRADING HISTORY

The Common Shares are listed and posted for trading on the TSXV under the trading symbol "TUK". The following table sets out the closing price range and trading volume of the Common Shares as reported by the TSXV for the periods indicated.

Period	High ($)	Low ($)	Volume (MM)
January 2025	0.16	0.09	28,478,601.00
February 2025	0.16	0.13	14,511,714.00
March 2025	0.15	0.09	16,612,847.00
April 2025	0.11	0.08	7,236,276.00

Page 28

May 2025	0.10	0.08	16,652,575.00
June 2025	0.09	0.07	3,987,338.00
July 2025	0.08	0.05	5,378,394.00
August 2025	0.07	0.04	6,512,387.00
September 2025	0.05	0.04	11,283,082.00
October 2025	0.05	0.04	5,327,389.00
November 2025	0.05	0.04	18,838,637.00
December 2025	0.05	0.03	10,450,789.00

PRIOR SALES

During the year ended December 31, 2025, the Corporation did not issue any securities that are outstanding but not listed or quoted on a marketplace other than as set forth below.

Date of Issuance	Description of Transaction	Number and Type of Securities	Price per Security/ Exercise Price^{(1)}
August 22, 2025	Stock Option Grant^{(2)}	240,000 Options	$0.05
April 3, 2025	Cashless Exercise of 2022 Warrants^{(3)}	103,154 Common Shares	$0.11
January 23, 2025	Exercise of Warrants^{(4)}	1,312,000 Common Shares	$0.075
January 27, 2025	Exercise of Warrants^{(4)}	400,000 Common Shares	$0.075
January 30, 2025	Exercise of Warrants^{(4)}	200,000 Common Shares	$0.075
January 31, 2025	Exercise of Warrants^{(4)}	100,000 Common Shares	$0.075
February 3, 2025	Exercise of Warrants^{(4)}	180,000 Common Shares	$0.075
February 4, 2025	Exercise of Warrants^{(4)}	320,000 Common Shares	$0.075
February 11, 2025	Exercise of Warrants^{(4)}	200,000 Common Shares	$0.075
February 18, 2025	Exercise of Warrants^{(4)}	1,000,000 Common Shares	$0.075
March 17, 2025	Exercise of Warrants^{(4)}	100,000 Common Shares	$0.075
March 20, 2025	Exercise of Warrants^{(4)}	200,000 Common Shares	$0.075
February 7, 2025	Exercise of 2022 Warrants^{(5)}	324,074 Common Shares	$0.11
February 21, 2025	Exercise of 2022 Warrants^{(5)}	250,000 Common Shares	$0.11
February 26, 2025	Exercise of 2022 Warrants^{(5)}	740,000 Common Shares	$0.11
March 5, 2025	Exercise of 2022 Warrants^{(5)}	250,000 Common Shares	$0.11
January 23, 2025	Exercise of Broker Warrants^{(6)}	70,400 Common Shares	$0.05
		70,400 Warrants	$0.075
January 27, 2025	Stock Option Grant^{(7)}	200,000 Options	$0.14
January 6, 2025	Stock Option Grant^{(8)}	220,000 Options	$0.095

Notes:
(1) Represents the issue price for Common Shares and the exercise price for securities convertible into Common Shares.
(2) On August 22, 2025, pursuant to the Option Plan, the Corporation granted an aggregate of 240,000 Options. The Options vest as to one-third on each of the first, second and third anniversaries of their grant date, have an exercise price of $0.05 per Common Share and expire on August 22, 2030.
(3) During the second quarter of 2025, 374,012 2022 Warrants were exercised on a cashless basis, resulting in the issuance of 103,154 Common Shares.
(4) During the first quarter of 2025, 4,012,000 Warrants were exercised for 4,012,000 Common Shares at an exercise price of $0.075 per Common Share, for total cash proceeds of $300,900.
(5) During the first quarter of 2025, 1,564,074 2022 Warrants were exercised for 1,564,074 Common Shares at an exercise price of $0.11 per Common Share, for total cash proceeds of $172,048.
(6) During the first quarter of 2025, the Corporation issued 70,400 Common Shares and 70,400 Warrants to satisfy the exercise of 70,400 Broker Warrants, the exercise price for which was $0.05 per Broker Warrant. Each Warrant is exercisable for one Common Share at an exercise price of $0.075. Total cash proceeds were $3,520.

Tuktu Resources Ltd.
2026 Annual Information Form

(7) On January 27, 2025, pursuant to the Option Plan, the Corporation granted an aggregate of 200,000 Options. The Options vest as to one-third on each of the first, second and third anniversaries of their grant date, have an exercise price of $0.14 per Common Share and expire on January 27, 2030.
(8) On January 6, 2025, pursuant to the Option Plan, the Corporation granted an aggregate of 220,000 Options. The Options vest as to one-third on each of the first, second and third anniversaries of their grant date, have an exercise price of $0.095 per Common Share and expire on January 6, 2030.

DIRECTORS AND OFFICERS

Name, Occupation and Security holdings

The names, province, and country of residence, positions and offices held with the Corporation, and principal occupation of the directors and executive officers of the Corporation are set out below and, in the case of directors, the period each has served as a director of the Corporation.

Name and Residence	Position held(4)	Principal Occupation for the last five years
Kathleen Dixon
Alberta, Canada	Director and Board
Chair since April 17, 2023(5)	BMO Capital Markets 2010–2023; Taggart Oil Corp 2024–present; Interim President & CEO, Tuktu, September–October 2025
Robert (Bob) Dales(1)
Alberta, Canada	Director since July 15, 2022	Businessman
William (Bill) Guinan(2)
Alberta, Canada	Director since July 15, 2022	Partner, Borden Ladner Gervais LLP, 1982–2021; Businessman 2021–present
Natalie Sweet(3)
Alberta, Canada	Director since October 19, 2022	Manager, Senior or Chief Geologist at Canadian Discovery Ltd., Point Break Energy, and Mount Bastion Oil and Gas.
Robert Yurchevich
Alberta, Canada	Director since June 4, 2025	Founder and President of Blackfriars Capital Management Inc.
Jeremy Hodder
Alberta, Canada	President and Chief Executive Officer since October 29, 2025	President and Chief Executive Officer of Tuktu since October 29, 2025. Prior thereto, President and CEO, Capillary Resources Corp.; Executive Consultant, ARC Financial Corp.; VP Operations, Primavera Resources Corp.; and Director, Construction, Drilling & Completions, Petronas Canada
Craig Wall
Alberta, Canada	Chief Financial Officer since February 13, 2026	Chief Financial Officer of Tuktu since February 13, 2026. Prior thereto, VP Finance, Corval Energy and Bighorn Energy Corp. Before that, senior roles at Real Resources, Arsenal Energy and Greenfire Resources

(1) The members of the Corporation's Audit Committee are Bob Dales, Bill Guinan and Robert Yurchevich.
(2) The members of the Corporation's Compensation and Governance Committee are Bill Guinan, Bob Dales and Kathleen Dixon.
(3) The members of the Corporation's Reserves, Safety and ESG Committee are Natalie Sweet (Chair), Kathleen Dixon and Jeremy Hodder.
(4) The terms of office of all directors of the Corporation will expire on the date of the next annual shareholders' meeting.
(5) Ms. Dixon assumed the Board Chair role in July 2024 and served as Interim President and Chief Executive Officer from September 17 to October 29, 2025.

Notes:

Tuktu Resources Ltd.

2026 Annual Information Form

The directors and officers of Tuktu, as a group, beneficially own or control or direct, directly or indirectly, an aggregate of 44,806,808 Common Shares as of April 21, 2026, representing approximately 16.87% of the issued and outstanding Common Shares.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Cease Trade Orders

To the knowledge of the Corporation, no director or executive officer of the Corporation (nor any personal holding company of any of such persons) is, as of the date of this Annual Information Form, or was within 10 years before the date of this Annual Information Form, a director, chief executive officer or chief financial officer of any company (including the Corporation), that: (a) was subject to a cease trade order (including a management cease trade order), an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an "Order"), that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or (b) was subject to an Order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

Bankruptcies

To the knowledge of the Corporation, no director or executive officer of the Corporation (nor any personal holding company of any of such persons), or shareholder holding a sufficient number of securities of the Corporation to affect materially the control of the Corporation: (a) is, as of the date of this Annual Information Form, or has been within the 10 years before the date of this Annual Information Form, a director or executive officer of any company (including the Corporation) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or (b) has, within the 10 years before the date of this Annual Information Form, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder

Penalties or Sanctions

Conflict of Interest

Certain officers and directors of the Corporation are also officers and/or directors of other entities engaged in the oil and gas business generally. As a result, situations may arise where the interest of such directors and officers conflict with their interests as directors and officers of other companies. The resolution of such conflicts is governed by applicable corporate laws, which require that directors

Tuktu Resources Ltd.
2026 Annual Information Form

act honestly, in good faith and with a view to the best interests of the Corporation. Conflicts, if any, will be handled in a manner consistent with the procedures and remedies set forth in the ABCA. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided by the ABCA.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

To the knowledge of management of the Corporation, there are no legal proceedings or regulatory actions material to the Corporation to which the Corporation is a party, or was a party to during the most recently completed financial year, or of which any of its properties is the subject matter, or was the subject matter of during the most recently completed financial year, nor are there any such proceedings known to the Corporation to be contemplated. There have been no penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority and the Corporation has not entered to any settlement agreements with a court or securities regulatory authority.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There are no material interests, direct or indirect, of any: (a) director or executive officer of Tuktu; (b) person or company that beneficially owns, or controls or directs, directly or indirectly, more than 10% of any class or series of Tuktu's voting securities; or (c) associate or affiliate of any of the persons or companies referred to in (a) or (b) above in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect Tuktu.

TRANSFER AGENT AND REGISTRAR

Computershare Investor Services Inc., at its offices in Calgary, Alberta, acts as the transfer agent and registrar for the Common Shares. Computershare Trust Company of Canada acts as Warrant Agent for the Warrants issued on December 28, 2023, May 28, 2024 and November 21, 2024.

MATERIAL CONTRACTS

Except for contracts entered into in the ordinary course of business, the Corporation has not entered into any material contracts within the last financial year.

INTERESTS OF EXPERTS

The only persons or companies who are named as having prepared or certified a report, valuation, statement or opinion described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by the Corporation during, or relating to, the Corporation's most recently completed financial year, and whose profession or business gives authority to the report, valuation, statement or opinion made by the person or company, are KPMG LLP, the Corporation's independent auditors, and Deloitte, the Corporation's independent reserve evaluators.

To the Corporation's knowledge, no registered or beneficial interests, direct or indirect, in any securities or other property of the Corporation or of one of the Corporation's associates or affiliates (i) were held by the Deloitte or by the "designated professionals" (as defined in Form 51-102F2) of Deloitte, when Deloitte prepared its reports, valuations, statements or opinions referred to herein as having been prepared by Deloitte, (ii) were received by Deloitte or the designated professionals of Deloitte after Deloitte prepared the reports, valuations, statements or opinions in question, or (iii) is to be received by Deloitte or the designated professionals of Deloitte.

Tuktu Resources Ltd.
2026 Annual Information Form

Neither Deloitte nor any director, officer or employee of Deloitte is or is expected to be elected, appointed or employed as a director, officer or employee of the Corporation or of any associate or affiliate of the Corporation.

KPMG LLP are the auditors of the Corporation and have confirmed that they are independent with respect to the Corporation within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations.

INDUSTRY CONDITIONS

Companies operating in the Canadian oil and gas industry are subject to extensive regulation and control of operations (including with respect to land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government as well as with respect to the pricing and taxation of petroleum and natural gas through legislation enacted by, and agreements among, the federal and provincial governments of Canada, all of which should be carefully considered by investors in the Western Canadian oil and gas industry. All current legislation is a matter of public record, and the Corporation is unable to predict what additional legislation or amendments governments may enact in the future.

The Corporation's assets and operations are regulated by administrative agencies that derive their authority from legislation enacted by the applicable level of government. Regulated aspects of the Corporation's upstream oil and natural gas business include all manner of activities associated with the exploration for and production of oil and natural gas, including, among other matters: (i) permits for the drilling of wells and construction of related infrastructure; (ii) technical drilling and well requirements; (iii) permitted locations and access to operation sites; (iv) operating standards regarding conservation of produced substances and avoidance of waste, such as restricting flaring and venting; (v) minimizing environmental impacts, including by reducing emissions; (vi) storage, injection and disposal of substances associated with production operations; and (vii) the abandonment and reclamation of impacted sites. In order to conduct oil and natural gas operations and remain in good standing with the applicable federal or provincial regulatory scheme, producers must comply with applicable legislation, regulations, orders, directives and other directions (all of which are subject to governmental oversight, review and revision, from time to time). Compliance in this regard can be costly and a breach of the same may result in fines or other sanctions.

The discussion below outlines some of the principal aspects of the legislation, regulations, agreements, orders, directives and a summary of other pertinent conditions that impact the oil and gas industry in the Province of Alberta, where the Corporation's assets are located. While these matters do not affect the Corporation's operations in any manner that is materially different than the manner in which they affect other industry participants with similar assets and operations, investors should consider such matters carefully.

Pricing and Marketing in Canada

Crude Oil

Oil producers are entitled to negotiate volume and sales contracts directly with purchasers. As a result, macroeconomic and microeconomic market forces determine the price of oil. Worldwide supply and demand factors are the primary determinant of oil prices, but regional market and transportation issues also influence prices. The specific price that a producer receives will depend, in part, on oil quality, prices of competing products, distance to market, offtake capacity, availability of transportation, value of refined products, supply/demand balance and contractual terms of sale.

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2026 Annual Information Form

The trajectory of oil prices continues to be subject to uncertainty and volatility. In 2024, oil prices posted a fall for a second year as a result of stalling post-pandemic demand recovery and U.S. and non-OPEC+ producers contributing to global oversupply, despite geopolitical tensions in the Middle East and shipping disruptions in the Red Sea. In June 2023, OPEC+ producers agreed to target lower oil supply, with voluntary production cuts extended in December 2024 and a plan to gradually phase out these adjustments by the latter half of 2026. In 2025, global oil markets remained volatile due to continued geopolitical instability, including escalations between Israel and Iran, ongoing Houthi attacks on shipping in the Red Sea, and persistent uncertainty surrounding the conflicts in Ukraine and the Middle East.

Over the past year, U.S. tariffs on certain Canadian products, including energy, along with Canada's reciprocal measures, have added complexity to cross-border energy trade. Canadian oil and gas production has nevertheless been supported by the increased pipeline capacity of the Trans Mountain Pipeline to a total of 890,000 barrels per day since its expansion opened in May 2024, the commencement of commercial operations at LNG Canada's export terminal in mid-2025, and increased export capacity on the U.S. pipeline system moving Canadian production to Midwest and Gulf Coast refineries. The completion of the Trans Mountain expansion has enabled crude shipments to Asia and Europe, with China, South Korea, and India emerging as major buyers. See "Risk Factors – Impact of U.S. Legislative and Regulatory Policies".

Natural Gas

Natural gas prices in Western Canada have been constrained in recent years, reaching record lows in 2025, due to increasing North American supply, limited access to markets and limited storage capacity. The war between Russia and Ukraine, which began in 2022, significantly disrupted the supply of natural gas to Europe and caused a period of historically high global LNG prices as Europe shifted to LNG imports. Global LNG supply has since kept up with global demand, and prices have contracted. However, the conflict remains ongoing and continues to contribute to geopolitical uncertainty in global energy markets.

Gas prices within north America are impacted by global LNG prices, more so now than in the past, since the USA has become the largest LNG producer in the world. The USA currently consumes some 13 Bcf/d in their LNG plants, and experts have forecasted that some 28 Bcf/d may be liquefied and exported overseas. As the USA exports more LNG, Canadian natural gas prices could more closely follow global LNG prices, minus some discount. This will likely decrease gas price volatility, but global political issues, particularly related to those countries that supply oil and gas, will likely persist and some measure of gas price volatility will persist. There is also a drive to build LNG plants in Canada, as described below, but the pace at which these plants are approved and constructed lags significantly that of the USA.

In 2018-2019, the AECO spot price occasionally fell below $0/MMBtu, due to an extended pipeline maintenance program by TransCanada Energy Ltd. This program lasted longer than expected and strained cash flows of many companies that sold into the AECO market. It is possible that such maintenance programs could occur again and impact Tuktu's revenue.

NGLs

The pricing of condensates and other NGL such as ethane, butane and propane sold in intra-provincial, inter-provincial and international trade is determined by negotiation between buyers and sellers. The profitability of NGL extracted from natural gas is based on the products extracted being of greater economic value as separate commodities than as components of natural gas and therefore commanding higher prices. Such prices depend, in part, on the quality of the NGL, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term,

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supply/demand balance, access to liquids fractionation and other contractual terms of sale. To date, there is no material NGL production within Tuktu, but the corporation anticipates increasing NGL production in the future, following a successful capital program.

Exports from Canada

The Canada Energy Regulator (the "CER") regulates the export of oil, natural gas and NGL from Canada through the issuance of short-term orders and longer-term licenses pursuant to its authority under the Canadian Energy Regulator Act (the "CERA") and the Amended IAA (as defined herein). Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the CER and the federal government. The Corporation has not to date directly entered into contracts to export its production outside of Canada.

Transportation Constraints and Market Access

Capacity to transport production from Western Canada to Eastern Canada, the United States and other international markets has been, and continues to be, a major constraint on the exportation of crude oil, natural gas and NGL. Although numerous pipeline and other transportation projects have been announced or are underway, many proposed projects have been cancelled or delayed due to regulatory hurdles, court challenges, and economic and sociopolitical factors. Due in part to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced periods of low commodity pricing relative to other markets in the last several years.

Oil Pipelines

In Canada, the development and operation of inter-provincial and international pipelines fall within the federal government's jurisdiction and, under the CERA, new inter-provincial and international pipelines require a federal regulatory review and Cabinet approval before they can proceed. In recent years, however, there has been a perceived lack of policy and regulatory certainty in this regard such that, even when projects are approved, they often face delays due to actions taken by provincial and municipal governments and legal opposition related to issues such as Indigenous rights and title, the government's duty to consult and accommodate Indigenous peoples, and the sufficiency of all relevant environmental review processes. Export pipelines from Canada to the United States face additional unpredictability, because such pipelines also require approvals from several levels of government in the United States.

In June 2025, the federal government enacted the Building Canada Act (Bill C-5, the One Canadian Economy Act), granting the federal government authority to expedite approval of "national interest" infrastructure projects, including pipelines. While the legislation aims to reduce regulatory delays, it has drawn mixed reactions: industry stakeholders generally support its streamlining measures, whereas certain rights holders, particularly Indigenous groups, have expressed concerns regarding its implications. In August 2025, the federal government launched the Major Projects Office (the "MPO"), which is intended to help identify such projects and assist in fast-tracking their development.

On November 27, 2025, the governments of Canada and Alberta signed a Memorandum of Understanding (the "Canada-Alberta MOU") to collaborate on supporting the development of oil and gas resources, renewable energy, critical minerals, and other resource sectors in Western Canada. In the Canada-Alberta MOU, the federal government committed to supporting a new pipeline that will deliver low-emission bitumen to the northern British Columbia coast for shipping to Asian markets, if certain conditions are met by the Alberta government. The Alberta government has agreed to prepare an application for the pipeline project and submit it to the MPO before July 1, 2026. The Canada-Alberta MOU also includes a federal government commitment to not implement the Oil and Gas Sector

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Greenhouse Gas Emissions Cap Regulations and the commitment of both levels of government to design and commit to sector-specific stringency factors for large Alberta emitters under Alberta's Technology Innovation and Emissions Reduction Regulation, and to continue the annual industrial carbon tax rate increase up to $130 per tonne. The agreements to be established under the Canada-Alberta MOU are expected to be finalized in 2026 and 2027.

Producers negotiate with pipeline operators to transport their products to market on a firm, spot or interruptible basis depending on the specific pipeline and the specific substance. Transportation availability is highly variable across different jurisdictions and regions. This variability can determine the nature of transportation commitments available, the number of potential customers and the price received.

Specific Pipeline Updates

In December 2023, regulators in the State of Michigan approved Enbridge's Line 5 Tunnel Replacement Project ("Line 5"), marking the end of a more than three year-long evaluation process. Line 5 is seen as crucial infrastructure supplying Michigan, Ontario and Quebec. This approval begins the process of replacing seven kilometres of the current pipeline with a new underwater tunnel in the Straights of Mackinac. While state approval has been granted, Line 5 still requires federal permitting from the U.S. Army Corps of Engineers, which has published a draft environmental impact statement and initiated the federal review process. The U.S. Army Corps of Engineers had previously indicated that a final federal permitting decision was expected in the fall of 2025; however, that decision has since been delayed into 2026.

Construction of the Trans Mountain Pipeline expansion, which received Cabinet approval in November 2016, was completed and commenced commercial operations in April 2024, and service began in May 2024. The original pipeline and the newly completed expansion now operate collectively. As announced by Trans Mountain on February 3, 2025, since May 1, 2024, the company has sent roughly half of the shipments from its marine terminal to countries other than the United States on the Pacific Rim, and half have gone to refineries on the west coast of the United States.

The United States presidential election concluded in the fall of 2024, which led to the inauguration of President Trump. The 2024 election allowed Republicans to gain a three-seat majority in the U.S. Senate and maintain control of the U.S. House of Representatives. With the change of the United States administration in 2025, there is additional uncertainty regarding the actions the Trump administration may take with respect to export pipelines and cross-border energy trade.

Natural Gas and Liquified Natural Gas ("LNG")

Natural gas prices in Western Canada have been constrained in recent years, reaching record lows in 2025, due to increasing North American supply, limited access to markets and limited storage capacity. Companies that secure firm access to infrastructure to transport their natural gas production out of Western Canada may be able to access more markets and obtain better pricing. Companies without firm access may be forced to accept spot pricing in Western Canada for their natural gas, which is generally lower than the prices received in other North American markets.

Required repairs or upgrades to existing pipeline systems in Western Canada have also led to reduced capacity and apportionment of access, the effects of which have been exacerbated by storage limitations. In October 2020, TC Energy Corporation ("TC") received federal approval to expand the Nova Gas Transmission Line system (the "NGTL System"). The NGTL System is currently implementing a $9.9 billion infrastructure program to add 3.58 billion cubic feet per day of capacity. In July 2024, TC announced an historic equity interest purchase agreement with an Indigenous-owned investment partnership which would enable up to 72 Indigenous communities to become equity owners

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of the network of infrastructure assets spanning Western Canada; however, as of September 2024, the deal has been delayed.

In 2025, LNG Canada became fully operational as the country's first large-scale LNG export terminal, marking a significant milestone in Canada's emergence as a global LNG supplier. The project exported its first cargo from the Kitimat terminal in July 2025, and by September had already shipped ten cargoes to international markets, with export volumes continuing to rise thereafter. In addition, on August 6, 2025, JGC and Fluor were awarded a contract to update the Front-End Engineering and Design for the proposed Phase 2 expansion, which aims to double the facility's annual LNG production capacity.

While a number of other LNG export plants have been proposed in Canada, regulatory and legal uncertainty, opposition from environmental and Indigenous groups and changing market conditions have resulted in the cancellation or delay of many of these projects. In December 2019, the CER approved a 40-year export licence for the Woodfibre LNG project, a net zero LNG export facility being developed through a joint venture between Pacific Energy Corporation (Canada) Limited and Enbridge Inc. By the end of September 2025, the Woodfibre LNG Project was more than 50% complete and is expected to be substantially completed in the third quarter of 2027. In addition, in June 2024 the proposed Cedar LNG project, a floating LNG facility also located in British Columbia, reached a successful final investment decision, and is expected to be in service in late 2028.

In January 2025, the U.S. Department of Energy resumed processing LNG export applications to countries without a free trade agreement, ending the temporary pause implemented by the previous administration. Export permits have been approved for new LNG projects in U.S. jurisdictions such as Jefferson County, Texas and Cameron Parish, Louisiana. In March 2025, President Trump announced plans to develop a $44 billion LNG project in Alaska for export to Asian markets. This was followed by Baker Hughes' announcement in November 2025 of its definitive agreement to provide key equipment for the project. It is uncertain at this time the effect this may have on Canadian LNG export projects, including demand for the export of LNG.

Development of both provincial and federal frameworks may also impose restrictions on natural gas and LNG projects in Canada, particularly as provincial and federal governments work to achieve emissions reduction targets. Such frameworks are expected to introduce more stringent restrictions on carbon emissions, with the potential for increased compliance costs, operational delays and restrictions on new project approvals. See also "Industry Conditions – Federal Environmental Regulations", "Industry Conditions – Alberta Environmental Regulations", "Industry Conditions – Federal Climate Change Regulations" and "Industry Conditions – Alberta Climate Change Regulations".

International Trade Agreements

Canada is party to a number of international trade agreements with other countries around the world that generally provide for, among other things, preferential access to various international markets for certain Canadian export products. Examples of such trade agreements include the Comprehensive Economic and Trade Agreement, ("CETA") the Comprehensive and Progressive Agreement for Trans-Pacific Partnership and, most prominently, the United States Mexico Canada Agreement (the "USMCA"), which replaced the former North American Free Trade Agreement ("NAFTA") on July 1, 2020. Because the United States remains Canada's primary trading partner and the largest international market for the export of oil, natural gas and NGL from Canada, the implementation of the USMCA could impact Western Canada's oil and gas industry, as a whole, including the Corporation's business.

Tuktu Resources Ltd.
2026 Annual Information Form

In early 2025, the U.S. announced a 25% broad-based tariff on goods exported out of Canada into the United States, other than energy products (including oil and natural gas), which would be subject to a 10% tariff. In response, the Canadian government announced retaliatory tariffs. On March 4, 2025, the tariffs against Canada came into effect as initially promulgated; however, certain applications were paused on March 6, 2025, until April 2, 2025. Subsequent to April 2025, the U.S. maintained and expanded additional measures that increased both the scope and volatility of tariff-related costs and compliance, including increased Section 232 tariffs on steel and aluminum (including derivatives) and sector-specific tariffs on copper, softwood lumber and certain other products. On February 20, 2026, the U.S. Supreme Court ("SCOTUS") held that the Trump administration lacked legal authority to impose certain tariffs under the International Emergency Economic Powers Act ("IEEPA") and U.S. Customs and Border Protection announced that it would cease collecting the affected tariffs. In response to the SCOTUS decision, the Trump administration indicated that it intends to impose alternative tariffs or adopt other trade measures on its trading partners, including Canada. SCOTUS' decision, the Trump administration's response, and the ongoing USMCA review add further uncertainty regarding whether crude oil, natural gas, and NGL exports to the U.S. could ultimately be subject to tariffs or other trade measures. The USMCA is scheduled for a comprehensive joint review on July 1, 2026, which may result in modifications to the trade framework governing cross-border energy commerce. As Canada-U.S. trade relations continue to evolve, the potential for further tariff-related conflicts could introduce additional volatility and risks to the Corporation's operations.

Canada is also party to the Comprehensive Economic and Trade Agreement ("CETA"), which provides for duty-free, quota-free market access for Canadian crude oil and natural gas products to the European Union, although it has not received full ratification by national legislatures in the European Union. Following the United Kingdom's departure from the European Union on January 31, 2020, the United Kingdom and Canada entered into the Canada-United Kingdom Trade Continuity Agreement ("CUKTCA"), which replicates CETA on a bilateral basis to maintain the status quo of the Canada-United Kingdom trade relationship. On January 25, 2024, the United Kingdom formally notified Canada that it had paused negotiations for a new free trade agreement, though the CUKTCA remains in force. Canada and 10 other countries signed the Comprehensive and Progressive Agreement for Trans-Pacific Partnership (the "CPTPP"), which allows for preferential market access among its parties. The CPTPP is in force among Canada, Australia, Japan, Mexico, New Zealand, Singapore, Vietnam, Peru, Malaysia, Chile, Brunei Darussalam and the United Kingdom. In August 2023, an updated version of the Canadian Free Trade Agreement ("CFTA") was published, aiming to create a more robust and equitable trade environment within Canada. While it is uncertain what effect CETA, CUKTCA, CPTPP, CFTA or any other trade agreements will have on the petroleum and natural gas industry in Canada, the completion of the Trans Mountain Pipeline expansion and commencement of operations at LNG Canada's Kitimat facility may facilitate shipping access to these markets for Canadian producers. However, even with these projects, the infrastructure for the offshore export of crude oil and natural gas remains constrained and may limit the ability of Canadian crude oil and natural gas producers to benefit from such trade agreements.

Marine Tankers

The Oil Tanker Moratorium Act (Canada) (the "OTMA"), which was enacted in June 2019, imposes a ban on tanker traffic transporting crude oil or persistent crude oil products in excess of 12,500 metric tonnes to and from ports located along British Columbia's north coast. The ban may prevent pipelines from being built to, and export terminals from being located on, the portion of the British Columbia coast subject to the moratorium. In response to discussions about potential limited exemptions related to future oil pipelines in Northern British Columbia, the British Columbia government signed the North Coast Protected Declaration on November 5, 2025 that urges the federal government to uphold and defend the OTMA, and to reject any exemptions. However, in the Canada-Alberta MOU, the federal government indicated an openness to making adjustments to the OTMA to assist in the construction of a new Alberta pipeline that will export bitumen to Asian markets.

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Land Tenure

Mineral Rights

With the exception of Manitoba, each provincial government in Western Canada owns most of the mineral rights to the oil and natural gas located within their respective provincial borders. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits (collectively, “leases”) for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments in lieu thereof. The provincial governments in Western Canada conduct regular land sales where oil and natural gas companies bid for the leases necessary to explore for and produce oil and natural gas owned by the respective provincial governments. These leases generally have fixed terms, but they can be continued beyond their initial terms if the necessary conditions are satisfied.

All of the provinces of Western Canada have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a disposition. In addition, Alberta has a policy of “shallow rights reversion” which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for new leases and licences. British Columbia has a policy of “zone specific retention” that allows a lessee to continue a lease for zones in which they can demonstrate the presence of oil or natural gas, with the remainder reverting to the Crown.

In addition to Crown ownership of the rights to oil and natural gas, private ownership of oil and natural gas (i.e. freehold mineral lands) also exists in Western Canada. Rights to explore for and produce privately owned oil and natural gas are granted by a lease or other contract on such terms and conditions as may be negotiated between the owner of such mineral rights and companies seeking to explore for and/or develop oil and natural gas reserves.

An additional category of mineral rights ownership includes ownership by the Canadian federal government of some legacy mineral lands and within Indigenous reservations designated under the Indian Act (Canada). Indian Oil and Gas Canada manages subsurface and surface leases in consultation with applicable Indigenous peoples, for the exploration and production of oil and natural gas on Indigenous reservations through An Act to Amend the Indian Oil and Gas Act and the accompanying regulations. The Corporation does not have operations on Indigenous reserve lands.

Surface Rights

To develop oil and natural gas resources, producers must also have access rights to the surface lands required to conduct operations. For Crown lands, surface access rights can be obtained directly from the government. For private lands, access rights can be negotiated with the landowner. Where an agreement cannot be reached, however, each province has developed its own process that producers can follow to obtain and maintain the surface access necessary to conduct operations throughout the lifespan of a well, including notification requirements and providing compensation to affected persons for lost land use and surface damage. Similar rules apply to facility and pipeline operators.

Royalties and Incentives

General

Each province has legislation and regulations in place to govern Crown royalties and establish the royalty

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rates that producers must pay in respect of the production of Crown resources. The royalty regime in each province is in addition to applicable federal and provincial taxes and is a significant factor in the profitability of oil sands projects and oil, natural gas and NGL production. Royalties payable on production from lands where the Crown does not hold the mineral rights are negotiated between the mineral freehold owner and the lessee, though certain provincial taxes and other charges on production or revenues may be payable. Royalties from production on Crown lands are determined by provincial regulation and are generally calculated as a percentage of the value of production.

Producers and working interest owners of oil and natural gas rights may create additional royalties or royalty-like interests, such as overriding royalties, net profits interests and net carried interests, through private transactions, the terms of which are subject to negotiation.

Occasionally, both the federal and provincial governments in Western Canada create incentive programs for the oil and gas industry. These programs often provide volume-based incentives, royalty rate reductions, royalty holidays or royalty tax credits and may be introduced when commodity prices are low to encourage exploration and development activity. Governments may also introduce incentive programs to encourage producers to prioritize certain kinds of development or utilize technologies that may enhance or improve recovery of oil, natural gas and NGL, or improve environmental performance. In addition, from time-to-time, the federal government creates incentives and other financial aid programs intended to assist businesses operating in the oil and gas industry as well as other industries in Canada.

Crown Royalties

In Alberta, oil and natural gas producers are responsible for calculating their royalty rate on an ongoing basis. The Crown's royalty share of production is payable monthly and producers must submit their records showing the royalty calculation.

Under Alberta's modern royalty framework (the "MRF"), royalty percentages are applied to the gross revenue generated from all hydrocarbons, with no differentiation between produced substances, and wells are charged a flat 5% royalty rate until revenues exceed a normalized well cost allowance, which is based on vertical well depth and lateral length. Any changes to the royalty regime in Alberta may have a material effect on the Corporation. See "Risk Factors".

In addition to any negotiated royalty amount payable to the freehold mineral owner, producers of oil and natural gas from freehold lands in Alberta are required to pay annual freehold mineral taxes. The freehold mineral tax is a tax levied by the Government of Alberta on the value of oil and natural gas production from non-Crown lands and is derived from the Freehold Mineral Rights Tax Act (Alberta). The freehold mineral tax is levied on an annual basis on calendar year production using a tax formula that takes into consideration, among other things, the amount of production, the hours of production, the value of each unit of production, the tax rate and the percentages that the owners hold in the title. The basic formula for the assessment of freehold mineral tax is: revenue less allocable costs equals net revenue divided by wellhead production equals the value based upon unit of production. If payors do not wish to file individual unit values, a default price is supplied by the Crown.

On average, the tax levied is 4% of revenues reported from fee simple mineral title properties. In July 2019, the Government of Alberta enacted the Royalty Guarantee Act which provides certainty that no major changes will be made to the current oil and gas royalty structure for a period of at least ten years.

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Freehold Royalties and Taxes

Royalty rates for the production of privately owned oil and natural gas are negotiated between the producer and the resource owner. Producers and working interest participants may also pay additional royalties to parties other than the freehold mineral owner where such royalties are negotiated through private transactions.

The Government of Alberta levies annual freehold mineral taxes for production from freehold mineral lands. On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties and is payable by the registered owner of the mineral rights.

Incentives

The Government of Alberta has from time to time implemented drilling credits, incentives, or transitional royalty programs to encourage crude oil and natural gas development and new drilling. In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources, including coalbed methane wells, shale gas wells and horizontal crude oil and natural gas wells.

Regulatory Authorities and Environmental Regulation

General

The Canadian oil and gas industry is subject to environmental regulation under a variety of Canadian federal, provincial, territorial, and municipal laws and regulations, all of which are subject to governmental review and revision from time to time. Such regulations provide for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment, and reclamation of well, facility and pipeline sites. Compliance with such regulations can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licences and authorizations, civil liability, and the imposition of material fines and penalties. In addition, future changes to environmental legislation, including legislation related to air pollution and greenhouse gas ("GHG") emissions (typically measured in terms of their global warming potential and expressed in terms of carbon dioxide equivalent ("CO2e"), may impose further requirements on operators and other companies in the oil and gas industry.

Federal

Canadian environmental regulation is the responsibility of both the federal and provincial governments. While provincial governments and their delegates are responsible for most environmental regulation, the federal government can regulate environmental matters where they impact matters of federal jurisdiction or when they arise from projects that are subject to federal jurisdiction, such as interprovincial transportation undertakings, including pipelines and railways, and activities carried out on federal lands. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law prevails.

The CERA and the Impact Assessment Act (the "IAA") provide several important elements to the regulation of federally regulated major projects and their associated environmental assessments. The CERA separates the CER's administrative and adjudicative functions. The CER has jurisdiction over matters such as the environmental and economic regulation of pipelines, transmission infrastructure

and certain offshore renewable energy projects. In its adjudicative role, the CERA tasks the CER with reviewing applications for the development, construction, and operation of many of these projects, culminating in their eventual abandonment.

The IAA relies on a designated project list as a trigger for a federal assessment. Designated projects that may have effects on matters within federal jurisdiction will generally require an impact assessment administered by the Impact Assessment Agency (the "IA Agency") or, in the case of certain pipelines, a joint review panel comprised of members from the CER and the IA Agency. The impact assessment requires consideration of the project's potential adverse effects and the overall societal impact that a project may have, both of which may include a consideration of, among other items, environmental, biophysical, and socio-economic factors, climate change, and impacts to Indigenous rights. It also requires an expanded public interest assessment. Designated projects specific to the oil and gas industry include pipelines that require more than 75 kilometers of new rights of way and pipelines located in national parks, large scale in situ oil sands projects not regulated by provincial GHG emissions caps and certain refining, processing, and storage facilities.

The federal government has stated that an objective of the legislative changes was to improve decision certainty and turnaround times. Once a review or assessment is commenced under either the CERA or IAA, there are limits on the amount of time the relevant regulatory authority will have to issue its report and recommendation. Designated projects will go through a planning phase to determine the scope of the impact assessment, which the federal government has stated should provide more certainty as to the length of the full review process. On October 13, 2023, the SCC concluded that the "designated projects" component was partially unconstitutional due to its encroachment of provincial jurisdiction beyond federal authority. An interim guidance was enacted following the SCC Ruling. In June 2024, the federal government enacted amendments to the IAA through the Budget Implementation Act, 2024, No. 1 (the "Amended IAA"). The Amended IAA largely preserved the assessment framework of the pre-amendment IAA but replaced the assessment of designated projects from a broader consideration of potential adverse effects and societal impacts to a narrowed assessment of adverse effects, defined as non-negligible adverse changes, within the federal jurisdiction. In deciding whether an impact assessment is required, the Amended IAA added whether a means other than an impact assessment exists that would permit a jurisdiction to address the federal effects as another factor for the IA Agency's consideration. Additionally, the final project approval decision is subject to a heighted test and must consider whether the effects are likely to be, to some extent, significant. The full implications of the amendments are yet to be interpreted in practice though the Amended IAA has not fully addressed criticism from project proponents that the applicability, timelines and decision-making powers under the Amended IAA remain uncertain and unpredictable.

On June 13, 2023, Bill S-5, the Strengthening Environmental Protection for a Healthier Canada Act to amend the Canadian Environmental Protection Act ("CEPA"), received royal assent. The amendments include changes to the preamble of CEPA, which recognize that every individual in Canada has a right to a healthy environment. Section 2 of CEPA requires that the federal government protect this right, and that an implementation framework be developed to consider how this right will be administered under CEPA, which was published in July 2025. Further amendments include creating a risk assessment Plan of Chemical Management Priorities, setting out a multi-year assessment of substances and activities, and a commitment to consider the cumulative effects of these assessments on vulnerable populations.

On July 1, 2023, the CFS Regulations came into force, enacted under the Canadian Environmental Protection Act ("CEPA"). The objective of the clean fuel standard is to achieve 30 million tonnes of annual reductions in GHG emissions by 2030. The CFS Regulations requires liquid fossil fuel primary suppliers (i.e. producers and importers) to reduce the carbon intensity ("CI") of the liquid fossil fuels they produce in, and import into, Canada. The CFS Regulations has also established a credit market, whereby the annual CI reduction requirement can be met via three main categories of credit-creating

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actions: (i) actions that reduce the CI of the fossil fuel throughout its lifecycle; (ii) supplying low-carbon fuels; and (iii) specified end-use fuel switching in transportation. In the Canadian federal budget released on November 4, 2025 ("Budget 2025"), the federal government announced that it plans to introduce amendments to the CFS Regulations to help reduce reliance on imported fuels, strengthen domestic supply chains and support jobs in agriculture, forestry and waste sectors.

The Output-Based Pricing System Regulations enacted under the Greenhouse Gas Pollution Pricing Act (the "GGPPA") were amended on November 22, 2023. These amendments involved adding and revising output-based standards, enhancing implementation procedures, refining reporting accuracy, and encouraging voluntary participation. Notably, the updated Output-Based Pricing System (the "OBPS") introduced a 2% fixed annual tightening rate for most output-based standards starting from 2023. Sectors facing significant competition and carbon pricing-induced carbon leakage experienced a 1% adjusted tightening rate from 2023 onwards. In March 2025, the federal government made further amendments to the OBPS, aligning the system with the elimination of the federal fuel charge effective April 1, 2025.

On December 7, 2023, the federal government published the Regulatory Framework for an Oil and Gas Sector Greenhouse Gas Emissions Cap ("GHG Cap"), setting forth key elements of the GHG Cap including:

(i) a decline of emissions to meet net-zero by 2050; (ii) creating the legal upper bound on emissions (being the maximum emissions the whole sector may be allowed to emit per year) in a manner responsive to technically achievable emissions reductions and the global demand for oil and gas; (iii) minimal administrative burden; and (iv) ongoing monitoring and regular review of the standards.

On November 9, 2024, the Proposed Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations ("Proposed GHC Cap Regulation") was subsequently released by the federal government. The Proposed GHC Cap Regulation establishes registration and reporting requirements and a cap-and-trade system that apply to any oil and gas operators carrying out industrial activities including crude oil production, oil sands extraction and upgrading, natural gas extraction and LNG production. All operators captured by the Proposed GHC Cap Regulations would be required to register under the regulations by January 1, 2026. In addition to initial registration, operators are required to submit a production report describing cumulative production of all of the operator's facilities, as well as an annual report that sets out the quantity of production and GHGs attributed to each facility calculated in accordance with prescribed quantification methods described in the regulations. In addition to reporting requirements, operators with production greater than 365,000 boe per year must remit one compliance unit for each tonne of carbon dioxide equivalent tonne of their emissions. There are three categories of compliance units eligible to satisfy the operator's remittance obligations, consisting of: (i) at least 80% of the compliance units must be emission allowances prescribed by the minister, (ii) up to a maximum of 20% of compliance units may be satisfied by way of eligible Canadian offset credits, (iii) up to a maximum 10% of compliance units may be offset by the decarbonization units obtained from making contributions to a decarbonization program per carbon dioxide equivalent tonne.

The Government of Alberta issued a publication in January 2025 announcing that it intends to challenge the constitutionality of the Proposed GHG Cap Regulations after its enactment. To date, the Proposed GHG Cap Regulations have not been implemented. The federal government under Prime Minister Mark Carney has shifted the country's climate priority towards economic competitiveness. Additionally, per the Canada-Alberta MOU, the federal government has committed to not implementing the Proposed GHG Cap Regulations in consideration of the other commitments made in the Canada-Alberta MOU. Although originally expected to take effect in 2026, Budget 2025 introduced significant changes to Canada's climate-policy framework, creating uncertainty about whether the emissions cap will be implemented as proposed, revised, or withdrawn.

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In June 2023, the International Sustainability Standards Board ("ISSB") issued two international environmental reporting standards: IFRS S1, which addresses sustainability-related disclosure, and IFRS S2, which addresses climate-related disclosure. The Canadian Sustainability Standards Board ("CSSB") subsequently released for public comment substantially similar proposed Canadian versions of the international standards ("CSDS 1" and "CSDS 2"), which were finalized in December 2024 (collectively, the "Canadian Standards"). The Canadian Standards require issuers, among other things, to include quantitative data regarding their environmental considerations, to use scenario analysis in developing their disclosure, and to disclose Scope 3 emissions (i.e. indirect emissions from an organization's operations). The finalized Canadian Standards are substantially similar to IFRS S1 and S2 (and earlier drafts of CSDS 1 and CSDS 2), however they have extended implementation timelines for select criteria. Canadian companies are not required to follow the Canadian Standards at this time, however the Canadian Securities Administrators are considering amending Canadian reporting requirements to include certain aspects of these new Canadian Standards; to what extent they will be adopted remains unclear.

In June 2024, the federal Competition Act was amended to enact new deceptive marketing provisions targeting "greenwashing". The new provisions introduced unclear substantiation requirements for companies making environmental claims and significant fines for failing to meet the new requirements. As a result of the uncertainty with respect to the applicability of the new rules, some companies removed their environmental and sustainability-related disclosure from the public domain. In December 2024, the constitutionality of the new deceptive marketing provisions was challenged in the Alberta Court of King's Bench and the lawsuit remains ongoing. In late 2025, Bill C-15, An Act to implement certain provisions of the budget tabled in Parliament on November 4, 2025 ("Bill C-15 (2025)"), was introduced in the House of Commons. Among other measures, Bill C-15 (2025) would implement proposals announced in Budget 2025 to amend the greenwashing provisions of the Competition Act.

Alberta

The Alberta Energy Regulator (the "AER") is the principal regulator responsible for all energy resource development in Alberta. It derives its authority from the Responsible Energy Development Act and several related statutes including the Oil and Gas Conservation Act (the "OGCA"), the Oil Sands Conservation Act, the Pipeline Act, and the Environmental Protection and Enhancement Act. The AER is responsible for ensuring the safe, efficient, orderly, and environmentally responsible development of hydrocarbon resources, including allocating and conserving water resources, managing public lands, and protecting the environment. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Land and Property Rights Tribunal as well as the Alberta Ministry of Energy's responsibility for mineral tenure.

The Government of Alberta relies on regional planning to accomplish its resource development goals. Its approach to natural resource management provides for engagement and consultation with stakeholders and the public and examines the cumulative impacts of development on the environment and communities. While the AER is the primary regulator for energy development, several other governmental departments and agencies may be involved in land use issues, including the Alberta Ministry of Environment and Parks, the Alberta Ministry of Energy, the Aboriginal Consultation Office, and the Land Use Secretariat.

The Government of Alberta's land-use policy sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land-use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.

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The AER monitors seismic activity across Alberta to assess the risks associated with, and instances of, earthquakes induced by hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppants and additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate oil and natural gas production. In recent years, hydraulic fracturing has been linked to increased seismicity in certain areas in which hydraulic fracturing takes place, prompting regulatory authorities to investigate the practice further.

The AER has developed monitoring and reporting requirements that apply to all oil and natural gas producers working in certain areas where the likelihood of an earthquake is higher, and implemented the requirements in Subsurface Order Nos. 2, 6, and 7. The regions with seismic protocols in place are Fox Creek, Red Deer, and Brazeau. The Corporation does not have operations in Fox Creek, Red Deer and Brazeau.

Liability Management

Alberta

The Alberta Energy Regulator (AER) is responsible for overseeing liability management in conventional

upstream oil and natural gas operations across Alberta. This is primarily achieved through the implementation of the Liability Management Framework ("AB LM Framework") and the Liability Management Rating Program ("LMR"). However, recognizing the inadequacy of the previous LMR system in assessing companies' capacity to fulfill regulatory and liability obligations, the AER has introduced a more comprehensive approach under the AB LM Framework.

This holistic approach encompasses various initiatives, including the Licensee Capability Assessment System ("AB LCA"), Inventory Reduction Program ("AB IR Program"), and Licensee Management Program ("AB LM Program"). While incorporating elements from the previous LMR Program such as the Oilfield Waste Liability Program and the Large Facility Liability Management Program, these updated programs and policies reflects Alberta's evolving liability management landscape. Complementing the AB LM Framework, the Alberta government established the Orphan Fund to cover the costs associated with suspended, abandoned, remediated, and reclaimed oil and gas assets in instances where licensees are insolvent or fail to meet their obligations. To address the rise in orphaned assets, the government has provided loans to the Orphan Fund and covered levy payments during the COVID-19 pandemic to mitigate taxpayer burdens. In March 2025, the Alberta government approved a $144.45 million levy for the Orphan Well Association's 2025/26 operating budget.

The "Redwater" case decision by the Supreme Court of Canada has also influenced Alberta's liability management approach, prompting legislative changes that hold defunct licensees' working interest partners accountable for abandonment and reclamation obligations. Additionally, the AER now has the authority to direct the Orphan Fund to assume responsibility for assets lacking a responsible owner.

Key directives such as Directive 067, amended in 2021, and Directive 088, introduced in the same year, play pivotal roles in transitioning to the AB LM Framework. Directive 067 expands eligibility criteria for licensees, while Directive 088 replaces the AB LLR Program with the AB LCA, incorporating diverse factors for a comprehensive evaluation of corporate health.

Directive 088 introduces innovative initiatives like the AB LM Program and the AB IR Program, aimed at bolstering licensee oversight and setting industry-wide spending targets for abandonment and reclamation efforts. Within the AB LM Program, high-risk licensees may face diverse strategies from the AER to ensure compliance with regulatory and liability duties. Meanwhile, the AB IR Program

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establishes collective expenditure benchmarks for abandonment and reclamation activities across the industry, with individualized targets assigned to licensees based on provincial inactive liabilities and financial stability. Alternatively, certain licensees have the option to provide a security deposit instead of meeting closure expenditure targets. The industry-wide closure spend requirement for 2025 was set at $750 million and will remain at this level for 2026. In late 2025, the AER introduced mandatory annual closure spending requirements effective in 2026, reinforcing proactive liability reduction measures. On February 7, 2025, the AER released Bulletin 2025-04, providing for new editions of four directives: Directive 001: Requirements for Site-Specific Liability Assessment; Directive 011: Estimated Liability; Directive 068: Security Deposits; and Directive 088: Licensee Life-Cycle Management. The AB LCA considers a wide variety of factors to assess a licensee's liability rating, including but not limited to: (i) a licensee's financial health; (ii) its established total magnitude of liabilities; (iii) the remaining lifespan of its mineral resources; (iv) the management of its operations; (v) the rate of closure activities for its liabilities; and (vi) its compliance with administrative and regulatory requirements. These various factors then feed into a broader holistic assessment of a licensee under the AB LMF. In turn, that holistic assessment provides the basis for assessing risk posed by licence transfers, as well as any security deposit that the AER may require from a licensee in the event that the regulator deems a licensee at risk of not being able to meet its liability obligations.

Moreover, the AER has launched the Closure Nomination Program in 2023, enabling eligible parties to nominate specific oil and gas sites for closure. This program, accessible through the AER website's closure nomination form, aims to address ongoing risks and costs associated with inactive, abandoned, decommissioned, and unreclaimed oil and gas sites throughout the province.

Lastly, to incentivize abandonment and reclamation efforts, the AER has introduced programs like the Voluntary Area-Based Closure program, fostering industry collaboration and cost reduction through economies of scale.

Federal and Provincial Support for Liability Management

In April 2020, the Canadian Federal government allocated $1.7 billion to clean up orphaned and abandoned oil and gas wells in Alberta, Saskatchewan, and British Columbia. The goal was to create jobs and address environmental concerns related to these wells. The Government of Alberta developed the Liability Management Framework (LMF) in response to the federal funding. The LMF aims to improve and expedite reclamation efforts for orphaned and inactive wells, pipelines, and infrastructure. It upholds the polluter-pay principle, ensuring that industry takes responsibility for cleanup costs.

Climate Change Regulation

Climate change regulation at each of the international, federal, and provincial levels has the potential to significantly affect the future of the oil and gas industry in Canada. International agreements, federal initiatives, and provincial programs continue to shape emissions reduction targets, carbon pricing mechanisms, and reporting requirements. Current frameworks include measures such as carbon taxes, emissions caps, and incentives for low-carbon technologies, with ongoing reviews aimed at tightening standards to meet Canada's climate commitments. Any new laws and regulations (or additional requirements to existing laws and regulations) could have a material impact on the Corporation's operations and cash flow.

Federal

Canada has been a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") since 1992. Since its inception, the UNFCCC has instigated numerous policy changes with respect to climate governance. On April 22, 2016, 197 countries, including Canada, signed the

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Paris Agreement, committing to prevent global temperatures from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than 1.5° Celsius. In 2021, Canada strengthened this target to a 40–45% reduction below 2005 levels by 2030 and net-zero emissions by 2050.

During the course of the 2021 United Nations Climate Change Conference in Glasgow, Scotland, Canada pledged to: (i) reduce methane emissions in the oil and gas sector to 75% of 2012 levels by 2030; (ii) cease the export of thermal coal by 2030; (iii) impose a cap on emissions from the oil and gas sector; (iv) halt direct public funding to the global fossil fuel sector by the end of 2022; and (v) commit that all new vehicles sold in the country will be zero-emission on or before 2040. At the 2023 United Nations Climate Change Conference, Canada reaffirmed its commitment to transition away from fossil fuels and accelerate greenhouse gas reductions.

The Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change in 2016, setting out a plan to meet the federal government's 2030 emissions reduction targets. In March 2022, the Government of Canada also introduced Canada's 2030 Emissions Reduction Plan (the "2030 Reduction Plan"), which provides the building blocks for the Canadian economy to achieve 40% to 45% emissions reductions below 2005 levels by 2030. The 2030 Reduction Plan includes investments as well as carbon pricing and clean fuels measures. In 2025, the federal government published the 2025 Progress Report on the 2030 Emissions Reduction Plan, outlining the cumulative implementation status of measures.

On June 21, 2018, the federal government enacted the Greenhouse Gas Pollution Pricing Act (the "GGPPA"), which came into force on January 1, 2019. This regime has two parts: an output-based pricing system ("OBPS") for large industry (enabled by the Output-Based Pricing System Regulations) and a fuel charge (enabled by the Fuel Charge Regulations), both of which impose a price on CO2e emissions. This system applies in provinces and territories that request it and in those that do not have their own equivalent emissions pricing systems in place that meet the federal standards.

Originally under the federal plans, the price was set to escalate by $10 per tonne per year until it reached a maximum price of $50/tonne of CO2e in 2022; however, the federal government announced its intention to continue the annual price increases beyond 2022, with the benchmark price per tonne of CO2e increasing by $15 per year until reaching $170/tonne of CO2e in 2030. Effective April 1, 2025, the federal government introduced regulations that eliminated the federal fuel charge and removed the requirement for provinces and territories to maintain a consumer-facing carbon price. The previously scheduled increase to $95/tonne on April 1, 2025, no longer applies. While several provinces challenged the constitutionality of the GGPPA following its enactment, the Supreme Court of Canada confirmed its constitutional validity in a judgment released on March 25, 2021. Industrial carbon pricing systems, including Alberta's TIER and the federal OBPS where applicable, continue to apply to covered emissions sources.

On April 26, 2018, the federal government passed the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the "Federal Methane Regulations"). The Federal Methane Regulations seek to reduce emissions of methane from the oil and natural gas sector and came into force on January 1, 2020. By introducing several new control measures, the Federal Methane Regulations aim to reduce unintentional leaks and the intentional venting of methane and ensure that oil and natural gas operations use low-emission equipment and processes. Among other things, the Federal Methane Regulations limit how much methane upstream oil and natural gas facilities are permitted to vent. The federal government anticipates that these actions will reduce annual GHG emissions by about 20 megatonnes by 2030. In December 2023, the federal government proposed amendments to achieve a 75% reduction by 2030, introducing stricter limits, new prohibitions, and continuous monitoring requirements. These amendments are expected to take effect in 2027.

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The federal government has enacted the Multi-Sector Air Pollutants Regulation under the authority of the Canadian Environmental Protection Act, 1999, which regulates certain industrial facilities and equipment types, including boilers and heaters used in the upstream oil and gas industry, to limit the emission of air pollutants such as nitrogen oxides and sulphur dioxide.

The Canadian Net-Zero Emissions Accountability Act (the "CNEAA") received royal assent on June 29, 2021, and came into force on the same day. The CNEAA binds the Government of Canada to a process intended to help Canada achieve net-zero emissions by 2050. It establishes rolling five-year emissions-reduction targets and requires the government to develop plans to reach each target and support these efforts by creating a Net-Zero Advisory Body. The CNEAA also requires the federal government to publish annual reports that describe how departments and Crown corporations are considering the financial risks and opportunities of climate change in their decision-making.

The forceful transition of the energy supply to renewable energy has resulted in increased energy costs where it has been applied. In addition, heavy industry tends to gravitate to countries with less costly energy. The movement of energy supply to such countries will require Canada to expand its capacity to export hydrocarbons, principally through an extensive pipeline system, as well as LNG export facilities.

On June 8, 2022, the Canadian Greenhouse Gas Offset Credit System Regulations were published in the Canada Gazette. The regulations establish a regulatory framework to allow certain kinds of projects to generate and sell offset credits for use in the federal OBPS through Canada's Greenhouse Gas Offset Credit System. The system enables project proponents to generate federal offset credits through projects that reduce GHG emissions under a published federal GHG offset protocol. Offset credits can then be sold to those seeking to meet limits imposed under the OBPS or those seeking to meet voluntary targets.

On June 20, 2022, the Clean Fuel Regulations came into force, establishing Canada's Clean Fuel Standard. The Clean Fuel Standard aims to discourage the use of fossil fuels by increasing the price of those fuels when compared to lower-carbon alternatives. Taking effect in July 2023, the Clean Fuel Standard imposes obligations on primary suppliers of transportation fuels in Canada and requires fuels to contain a minimum percentage of renewable fuel content and meet emissions caps calculated over the life cycle of the fuel. The Clean Fuel Regulations also establish a market for compliance credits. Compliance credits can be generated by primary suppliers, among others, through carbon capture and storage, producing or importing low-emission fuel, or through end-use fuel switching (for example, operating an electric vehicle charging network).

The Government of Canada has developed a Carbon Management Strategy, whereby it aims to deploy various carbon management technologies, including carbon capture, to help achieve federal climate goals. Carbon capture, utilization and storage ("CCUS") is a technology that captures carbon dioxide from facilities, including industrial or power applications, or directly from the atmosphere. The captured carbon dioxide is then compressed and transported for permanent storage in underground geological formations or used to make new products. As part of this strategy, the federal government has committed $319 million over seven years into research and development. In June 2024, the government enacted the Carbon Capture, Utilization, and Storage Investment Tax Credit ("CCUS ITC"), a refundable tax credit available for eligible projects from January 1, 2022, until December 31, 2040, with a 50% reduction in credit value beginning in 2031.

In February 2026, the federal government introduced an updated national automotive strategy that includes more than $3 billion in planned financial commitments to support industry expansion, modernization, and diversification into additional export markets. As part of this initiative, the federal government will implement a new program to lower the cost of electric vehicles ("EVs") for Canadians, introduce new EV purchase and lease incentives for individuals and businesses, expand charging

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infrastructure, and advance a broader trade framework intended to enhance the competitiveness of the automotive sector. The strategy also replaces the Electric Vehicle Availability Standard (which required automakers to sell an increasing percentage of zero emission light-duty vehicles, reaching 100% by 2035) with updated greenhouse gas emissions standards and new targets of achieving 75% EV sales by 2035 and 90% by 2040. The Corporation is unable to predict how this new automotive strategy will impact the demand for fossil fuels and Canadian energy products.

On December 17, 2024, the federal government finalized the Clean Electricity Regulations, aimed at driving progress towards a net-zero electricity grid by 2050. The Clean Electricity Regulations establish stringent pollution emission standards without prescribing specific technologies. Although enacted in December 2024, the emission restrictions under the Clean Electricity Regulations will not come into effect until January 1, 2035. Under the Canada-Alberta MOU, the federal government suspended the application of the Clean Electricity Regulations in Alberta pending a new carbon pricing agreement, which will be administered through Alberta's TIER system.

The Government of Alberta previously contested the constitutionality of the draft Clean Electricity Regulations and urged the federal government to support Alberta's plan for achieving carbon neutrality by 2050. Following the release of the final draft of the Clean Electricity Regulations, in December 2024, the Government of Alberta issued a statement welcoming the extended time frame but continued to assert that the regulations strayed into provincial jurisdictions. Similarly, the Government of Saskatchewan plans to utilize the Saskatchewan First Act to establish a tribunal to assess the economic impacts of the Clean Electricity Regulations and issued a statement in December 2024 categorically rejecting the Clean Electricity Regulations. Consequently, there is a strong possibility that the Clean Electricity Regulations will face constitutional challenges.

Alberta

In December 2016, the Oil Sands Emissions Limit Act came into force, establishing an annual 100 megatonne limit for GHG emissions from all oil sands sites, but the regulations necessary to enforce the limit have not yet been developed. The delay in drafting these regulations has been inconsequential thus far, as Alberta's oil sands emitted roughly 85 megatonnes of GHG in 2024, well below the 100 megatonne limit.

In December 2019, the federal government approved Alberta's Technology Innovation and Emissions Reduction ("TIER") regulation, which applies to large emitters. The TIER regulation came into effect on January 1, 2020 and replaced the previous Carbon Competitiveness Incentives Regulation. The TIER regulation meets the federal benchmark stringency requirements for emissions sources covered in the regulation, and the federal backstop continues to apply to emissions sources not covered by the regulation. Since its introduction, TIER has undergone various amendments and program updates intended to refine compliance mechanisms and maintain alignment with federal benchmark stringency requirements. The TIER regulation will be subject to a subsequent review which must be completed by December 31, 2026 and the federal equivalency is scheduled to be re-assessed in early 2026. In the Canada-Alberta MOU, the federal government recognized Alberta's jurisdiction over its TIER regulations, agreeing to work with the province to develop a globally competitive carbon pricing system.

The Government of Alberta committed to lowering annual methane emissions from 2014 levels by 45% by 2025 and reached this target three years early. In November 2023, it was announced that Alberta had achieved its goal, reducing methane emissions by 51%, exceeding the initial 45% target. The Government of Alberta enacted the Methane Emission Reduction Regulation on January 1, 2020. On September 26, 2025, the Minister of the Environment and the Government of Alberta entered into a written agreement recognizing the equivalency between the Federal Methane Regulations and Alberta's Methane Emission Reduction Regulation under the Environmental Protection and

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Enhancement Act (Alberta). This equivalency agreement has a term of five years, applying until 2030. On October 23, 2025, the federal government made an order declaring the Federal Methane Regulations do not apply in Alberta.

Indigenous Rights

Constitutionally mandated government-led consultation with and, if applicable, accommodation of, the rights of Indigenous groups impacted by regulated industrial activity, as well as proponent-led consultation and accommodation or benefit sharing initiatives, play an increasingly important role in the Western Canadian oil and gas industry. In addition, Canada is a signatory to the United Nations Declaration of the Rights of Indigenous Peoples ("UNDRIP") and the principles set forth therein may continue to influence the role of Indigenous engagement in the development of the oil and gas industry in Western Canada. For example, in November 2019, the Declaration on the Rights of Indigenous Peoples Act ("DRIPA") became law in British Columbia. The DRIPA aims to align British Columbia's laws with UNDRIP. In June 2021, the United Nations Declaration on the Rights of Indigenous Peoples Act ("UNDRIP Act") came into force in Canada. Like British Columbia's DRIPA, the UNDRIP Act requires the Government of Canada to take all measures necessary to ensure the laws of Canada are consistent with the principles of UNDRIP and to implement an action plan to address UNDRIP's objectives. The federal government has sought to implement the UNDRIP Act by, among other things, creating a Secretariat within the Department of Justice to support Indigenous participation in the implementation of UNDRIP, consulting with Indigenous peoples to identify their priorities, drafting an action plan to align federal laws with UNDRIP, and implementing efforts to educate federal departments on UNDRIP's principles. On February 9, 2024, the Supreme Court of Canada rendered its decision regarding the Reference re An Act respecting First Nations, Inuit and Métis children, youth and families, in which it made clear its opinion that UNDRIP has been incorporated into Canada's domestic law. The federal government continues to encourage Indigenous equity ownership in energy and infrastructure projects, including LNG and pipelines.

Canada's 2023-2028 Action Plan was released in June 2023 and included 131 measures intended to provide a roadmap of actions Canada needs to take in partnership with Indigenous peoples to implement the principles and rights set out in the UNDRIP and to further advance reconciliation in a tangible way. In June 2024, the federal government tabled its Third Annual Progress Report on the implementation of the UNDRIP Act. Continued development of common law precedent regarding existing laws relating to Indigenous consultation and accommodation as well as the adoption of new laws such as DRIPA and the UNDRIP Act are expected to continue to add uncertainty to the ability of entities operating in the Canadian oil and gas industry to execute on major resource development and infrastructure projects, including, among other projects, pipelines. The Government of Canada has expressed that implementation of the UNDRIP Act has the potential to make meaningful change in how Indigenous peoples collaborate in impact assessment moving forward but has confirmed that the current IAA already establishes a framework that aligns with UNDRIP and does not need to be changed in light of the UNDRIP Act.

On June 29, 2021, the British Columbia Supreme Court issued a judgement in Yahey's British Columbia (the "Blueberry Decision"), in which it determined that the cumulative impacts of industrial development on the traditional territory of the Blueberry River First Nation ("BRFN") in northeast British Columbia had breached the BRFN's rights guaranteed under Treaty 8. The Blueberry Decision may have significant impacts on the regulation of industrial activities in northeast British Columbia and may lead to similar claims of cumulative effects across Canada in other areas covered by numbered treaties, as has been seen in Alberta.

On January 28, 2023, the Government of British Columbia and the BRFN signed the Blueberry River First Nations Implementation Agreement (the "BRFN Agreement"). The BRFN Agreement aims to address the cumulative effects of development on BRFN's claim area through restoration work,

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establishment of areas protected from industrial development, and a constraint on development activities. Such measures will remain in place while a long-term cumulative effects management regime is implemented. Specifically, the BRFN Agreement includes, among other measures, the establishment of a $200-million restoration fund by June 2025, an ecosystem-based management approach for future land-use planning in culturally important areas, limits on new petroleum and natural gas development and a new planning regime for future oil and gas activities. The BRFN will receive $87.5 million over three years, with an opportunity for increased benefits based on petroleum and natural gas revenue sharing and provincial royalty revenue sharing in the next two fiscal years.

The BRFN Agreement has acted as a blueprint for other agreements between the Government of British Columbia and Indigenous groups in Treaty 8 territory. In late January 2023, the Government of British Columbia and four Treaty 8 First Nations – Fort Nelson, Salteau, Halfway River and Doig River First Nations – reached consensus on a collaborative approach to land and resource planning (the "Consensus Agreement"). The Consensus Agreement implements various initiatives including a "cumulative effects" management system linked to natural resource landscape planning and restoration initiatives, new land-use plans and protection measures, and a new revenue-sharing approach to support the priorities of Treaty 8 First Nations communities. In July 2022, Duncan's First Nation filed a lawsuit against the Government of Alberta relying on similar arguments to those advanced successfully by the BRFN. Duncan's First Nation claims in its lawsuit that Alberta has failed to uphold its treaty obligations by authorizing development without considering the cumulative impacts on the First Nation's treaty rights. The long-term impacts of the Blueberry Decision and the Duncan's First Nation lawsuit on the Canadian oil and gas industry remain uncertain.

Accountability and Transparency

In 2015, the federal government's Extractive Sector Transparency Measures Act ("ESTMA") came into effect, which imposed mandatory reporting requirements on certain entities engaged in the "commercial development of oil, gas or minerals", including exploration, extraction and holding permits. All companies subject to ESTMA must report payments over CAD$100,000 made to any level of a Canadian or foreign government (including Indigenous groups), including royalty payments, taxes (other than consumption taxes and personal taxes), fees, production entitlements, bonuses, dividends (other than ordinary dividends paid to shareholders), infrastructure improvement payments and other prescribed categories of payments.

Bill S-211, An Act to enact the Fighting Against Forced Child Labour in Supply Chains Act and to amend the Customs Tariff (the "Modern Slavery Act") received royal assent on May 11, 2023 and came into force on January 1, 2024. Pursuant to the Modern Slavery Act, entities that meet certain criteria are required to file public reports annually on the steps they have taken prevent and reduce the use of forced labour and child labour in their supply chains.

RISK FACTORS

The Corporation is subject to risks that directly affect its business and operations, as well as indirect risks that impact third parties or industry generally.

Investors should carefully consider the risk factors set out below and consider all other information contained herein and, in the Corporation's other public filings, before making an investment decision. The risks set out below should be read in conjunction with the "Industry Conditions" section above. These risks are not an exhaustive list and should not be taken as a complete summary or description of all the risks associated with the Corporation's business and the oil and natural gas business generally.

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While some exposures may be reduced by the Corporation's risk management strategies, many risks are driven by external factors beyond its control or are of a nature which cannot be eliminated. Additional risks and uncertainties not currently known to management or that may currently not be considered material by management, could nevertheless also have an adverse effect on the Corporation's business.

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Corporation depends on its ability to find, acquire, develop, and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the Corporation's existing reserves, and the production from them, will decline over time as the Corporation produces from such reserves. A future increase in the Corporation's reserves will depend on both the ability of the Corporation to explore and develop its existing properties and its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Corporation will be able to continue to find satisfactory properties to acquire or participate in. Moreover, management of the Corporation may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participation uneconomic. There is also no assurance that the Corporation will discover or acquire further commercial quantities of oil and natural gas.

Future oil and natural gas exploration may involve unprofitable efforts from dry wells or from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completing (including hydraulic fracturing), operating and other costs. Completion of a well does not ensure a profit on the investment or recovery of drilling, completion, and operating costs.

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays in obtaining governmental approvals or consents, shut-ins of wells resulting from extreme weather conditions, insufficient storage or transportation capacity or geological and mechanical conditions. While diligent well supervision, effective maintenance operations and the development of enhanced oil recovery technologies can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills and other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment and cause personal injury or threaten wildlife. Particularly, the Corporation may explore for and produce sour gas in certain areas. An unintentional leak of sour gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Corporation.

Oil and natural gas production operations are also subject to geological and seismic risks, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

As is standard industry practice, the Corporation is not fully insured against all risks, nor are all risks insurable. Although the Corporation maintains liability insurance in an amount that it considers

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consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. See “Risk Factors – Insurance”. In either event, the Corporation could incur significant costs.

Prices, Markets and Marketing

The Corporation's ability to market its oil and natural gas may depend upon its ability to acquire capacity in pipelines that deliver oil, NGL and natural gas to commercial markets or contract for the delivery of oil and NGL by rail. Numerous factors beyond the Corporation’s control do, and will continue to, affect the marketability and price of oil and natural gas acquired, produced, or discovered by the Corporation, including (but not limited to): deliverability uncertainties related to the distance the Corporation’s reserves are from pipelines, railway lines and processing and storage facilities; operational problems affecting pipelines, railway lines and processing and storage facilities; and government regulation relating to prices, taxes, royalties, land tenure, allowable production and the export of oil and natural gas.

Oil and natural gas prices may be volatile for a variety of reasons including market uncertainties over the supply and demand of these commodities due to the current state of the world economies, OPEC actions, political uncertainties, wars, geopolitical instability, sanctions imposed on certain oil producing nations by other countries and other conflicts. Prices for oil and natural gas are also subject to the availability of foreign markets and the Corporation’s ability to access such markets. A material decline in prices could result in a reduction of the Corporation’s net production revenue. The economics of producing from some wells may change because of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes and the value of the Corporation’s reserves. The Corporation might also elect not to produce from certain wells at lower prices. Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the Corporation’s carrying value of its reserves, borrowing capacity, revenues, profitability, and cash flows from operations and may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects.

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for, and project the return on, acquisitions and development and exploitation projects.

Market Price Volatility

The trading price of the securities of oil and natural gas issuers is subject to substantial volatility often based on factors related and unrelated to the financial performance or prospects of the issuers involved. Factors unrelated to the Corporation’s performance could include macroeconomic developments nationally, within North America or globally, domestic, and global commodity prices, and/or current perceptions of the oil and natural gas market. In recent years, the volatility of commodities has increased due, in part, to the implementation of computerized trading and the decrease of discretionary commodity trading. In addition, the volatility, trading volume and share price of issuers have been impacted by increasing investment levels in passive funds that track major indices, as such funds only purchase securities included in such indices. In addition, in certain jurisdictions, institutions, including government sponsored entities, have determined to decrease their ownership in oil and natural gas entities which may impact the liquidity of certain securities and put downward pressure on the trading price of those securities. Similarly, the market price of the Common Shares of the Corporation could be subject to significant fluctuations in response to variations in the Corporation’s operating results, financial condition, liquidity, and other internal factors. Accordingly, the price at which the Common Shares of the Corporation will trade cannot be accurately predicted.

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Market events and conditions, including global excess crude oil and natural gas supply, actions taken by OPEC+, sanctions against, and civil unrest in Northern Africa, Iran and Venezuela, Russia and Ukraine, the Middle East, Israel and the West Bank and Gaza Strip, and Yemen, slowing growth in China and emerging economies, market volatility and disruptions in Asia, weakening global relationships, isolationist and punitive trade policies including tariffs, increased United States shale production, sovereign debt levels and political upheavals in various countries including growing anti-fossil fuel sentiment, have caused significant volatility in commodity prices. In 2024, oil prices posted a fall for a second year as a result of stalling post-pandemic demand recovery and the U.S. and non-OPEC+ producers contributed to the global oversupply, despite geopolitical tensions in the Middle East and shipping disruptions in the Red Sea due to attacks by Houthi rebel groups. In 2025, global oil markets remained volatile due to continued geopolitical instability, including escalations between Israel and Iran, ongoing Houthi attacks on shipping in the Red Sea, the collapse of the Syrian Assad regime, U.S. military action in Venezuela, and persistent uncertainty surrounding the conflicts in Ukraine and the Middle East. OPEC+ producers continued to target lower oil supply and implement voluntary production cuts in order to stabilize the price of oil, with a plan to gradually phase out these adjustments by the latter half of 2026. Crude oil and natural gas prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC+ actions, tariff and trade policy developments, and geopolitical instability. Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The anticipated benefits of acquisitions may not be achieved, and the Corporation may dispose of non-core assets for less than their carrying value on the financial statements as a result of weak market conditions.

The Corporation considers acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and the Corporation's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation. The integration of acquired businesses and assets may require substantial management effort, time and resources diverting management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided by third parties and the resources required to provide such services. In this regard, non-core assets may be periodically disposed of so the Corporation can focus its efforts and resources more efficiently. Depending on the market conditions for such non-core assets, certain non-core assets of the Corporation may realize less on disposition than their carrying value on the financial statements of the Corporation.

Political Uncertainty

The Corporation's results can be adversely impacted by political, legal, or regulatory developments in Canada and elsewhere that affect local operations and local and international markets. Changes in government, government policy or regulations, changes in law or interpretation of settled law, third-party opposition to industrial activity generally or projects specifically, and duration of regulatory reviews could impact the Corporation's existing operations and planned projects. This includes actions by regulators or other political actors to delay or deny necessary licenses and permits for the Corporation's activities or restrict the operation of third-party infrastructure that the Corporation relies on. Additionally, changes in environmental regulations, assessment processes or other laws, and

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increasing and expanding stakeholder consultation (including Indigenous stakeholders), may increase the cost of compliance or reduce or delay available business opportunities and adversely impact the Corporation's results.

Other government and political factors that could adversely affect the Corporation's financial results include increases in taxes or government royalty rates (including retroactive claims) and changes in trade policies and agreements. Further, the adoption of regulations mandating efficiency standards, and the use of alternative fuels or uncompetitive fuel components could affect the Corporation's operations. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources, and the success of these initiatives may decrease demand for the Corporation's products.

A change in federal, provincial, or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and natural gas industry including the balance between economic development and environmental policy. The oil and natural gas industry has become an increasingly politically polarizing topic in Canada, which has resulted in a rise in civil disobedience surrounding oil and natural gas development—particularly with respect to infrastructure projects. Protests, blockades, and demonstrations have the potential to delay and disrupt the Corporation's activities.

Danielle Smith was elected as Premier on October 11, 2022. Shortly after her appointment, Premier Smith introduced Bill 1: The Alberta Sovereignty Within a United Canada Act (the "Sovereignty Act"). The Sovereignty Act was passed on December 8, 2022 and received Royal Assent on December 15, 2022. The Sovereignty Act, amongst other things, enables the Alberta Government to choose which federal legislation, policies, or programs it will enforce in Alberta, providing an overriding right to not enforce those which the Alberta Government deems to be "harmful" to Alberta's interests or infringe on the Federal Constitution and its division of powers. The Sovereignty Act has been opposed by many, including the National Democratic Party and various Indigenous groups who have expressed concern as to how the Sovereignty Act will affect Indigenous rights and consultation obligations in Alberta. It is unclear what the effect the Sovereignty Act will have on Alberta, including the petroleum and natural gas industry. Alberta businesses and its federal and inter-provincial relationships, including the application of certain federal legislation in Alberta, such as the GGPPA and the IAA and the way in which the Alberta Government may address any legislative and policy gaps created. Although the Sovereignty Act has not yet been challenged in court, it is possible the Sovereignty Act's constitutionality will be challenged.

In addition, the potential impact on energy, tax and climate policy resulting from the Canadian federal election held on April 28, 2025 and any changes in government policy direction, including enactment of the Building Canada Act and the entry into the Canada-Alberta MOU described under "Industry Conditions", could create uncertainty for the Canadian energy industry. The precise duration and extent of the adverse impacts of the current macroeconomic and global economic activity on the Corporation's operations remains uncertain at this time.

Pandemic Risk

Severe disruptions in regional economies and the world economy can be caused by the outbreak of a contagious illness. Such pandemics and efforts to contain them could result in international, national and local border closings, travel restrictions, significant disruptions to business operations, supply chains, customer activity and demand, service cancellations, reductions and other changes, significant challenges in healthcare service preparation and delivery, and quarantines, as well as considerable general concern and uncertainty, all of which could negatively affect the economic environment and

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may in the future have further impacts, as was the case for the COVID-19 pandemic. It is not possible to predict what measures and restrictions may be imposed by governmental authorities and the period of time during which those measures and restrictions may apply. Economic and supply chain disruptions, including temporary staff shortages resulting from a pandemic, could further materially affect the Corporation's financial results and operations. A pandemic could also further and significantly impact global economic activity, including demand for hydrocarbons, and cause increased market volatility, continued changes to the macroeconomic environment and commodity prices in connection with ensuing economic disruption, supply shortages, trade disruption, temporary staff shortages and temporary closures of facilities in geographic locations more importantly impacted by the outbreak. The scope and severity of such disruptions and their impact on the Corporation's financial results and operations could be material.

Project Risks

The Corporation manages a variety of small and large projects in the conduct of its business. Project interruptions may delay expected revenues from operations. Significant project cost overruns could make a project uneconomic. The Corporation's ability to execute projects and to market oil and natural gas depends upon numerous factors beyond the Corporation's control, including, but not limited to: availability of processing capacity; availability and proximity of pipeline capacity; availability of storage capacity; availability of, and the ability to acquire, water supplies needed for drilling, hydraulic fracturing, and waterfloods or the Corporation's ability to dispose of water used or removed from strata at a reasonable cost and in accordance with applicable environmental regulations; effects of inclement and severe weather events, including fire, drought and flooding; availability of drilling and related equipment; unexpected cost increases; accidental events; currency fluctuations; regulatory changes; political uncertainty; timely receipt of regulatory approvals from the AER or otherwise, including with respect to Directive 076 application approvals; availability and productivity of skilled labour; and regulation of the oil and natural gas industry by various levels of government and governmental agencies. Because of these and other factors, the Corporation could be unable to execute projects on time, on budget, or at all.

Gathering and Processing Facilities, Pipeline Systems, Trucking and Rail

The Corporation delivers its products through gathering and processing facilities, pipeline systems and, in certain circumstances, by truck and rail. The amount of oil and natural gas that the Corporation can produce, and sell is subject to the accessibility, availability, proximity, and capacity of these gathering and processing facilities, pipeline systems, trucking and railway lines. Unexpected shutdowns or curtailment of capacity of pipelines for maintenance or integrity work or because of actions taken by regulators could also affect the Corporation's production, operations, and financial results.

A portion of the Corporation's production may, from time to time, be processed through facilities owned by third parties and over which the Corporation does not have control. From time to time, these facilities may discontinue or decrease operations either because of normal servicing requirements or because of unexpected events. A discontinuation or decrease of operations could have a material adverse effect on the Corporation's ability to process its production and deliver the same to market. Midstream and pipeline companies may take actions to maximize their return on investment, which may in turn adversely affect producers and shippers, especially when combined with a regulatory framework that may not always align with the interests of shippers.

Competition

The petroleum industry is competitive, and the Corporation competes with numerous other entities in the exploration, development, production and marketing of oil and natural gas. The Corporation's

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competitors include oil and natural gas companies that have substantially greater financial resources, staff, and facilities than those of the Corporation. Some of these companies not only explore for, develop, and produce oil and natural gas, but also carry on refining operations and market oil and natural gas on an international basis. As a result of these complementary activities, some of these competitors may have greater and more diverse competitive resources to draw on than the Corporation. The Corporation's ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price, process, and reliability of delivery and storage.

Cost of New Technologies

The petroleum industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. Other companies may have greater financial, technical and personnel resources that allow them to implement and benefit from technological advantages. There can be no assurance that the Corporation will be able to respond to such competitive pressures and implement such technologies on a timely basis, or at an acceptable cost. If the Corporation does implement such technologies, there is no assurance that the Corporation will do so successfully. One or more of the technologies currently utilized by the Corporation or implemented in the future may become obsolete. If the Corporation is unable to utilize the most advanced commercially available technology, or is unsuccessful in implementing certain technologies, its business, financial condition and results of operations could also be adversely affected in a material way.

Alternatives To, and Changing Demand For, Petroleum Products

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy generation systems could reduce the demand for oil, natural gas and liquid hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to decrease the use of hydrocarbons and encourage the use of renewable fuel alternatives, which may lessen the demand for petroleum products and put downward pressure on commodity prices. Advancements in energy efficient products have a similar effect on the demand for oil and natural gas products. The Corporation cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Corporation's business, financial condition, results of operations and cash flow by decreasing the Corporation's profitability, increasing its costs, limiting its access to capital, and decreasing the value of its assets.

Regulatory

The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for oil and natural gas and increase the Corporation's costs, either of which may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. Further, the ongoing third-party challenges to regulatory decisions or orders has reduced the efficiency of the regulatory regime, as the implementation of the decisions and orders have experienced delays resulting in uncertainty and interruption to business of the oil and natural gas industry.

To conduct oil and natural gas operations, the Corporation will require regulatory permits, licenses, registrations, approvals, and authorizations from various governmental authorities at the municipal, provincial and federal level. There can be no assurance that the Corporation will be able to obtain all the permits, licenses, registrations, approvals and authorizations that may be required to conduct

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operations that it may wish to undertake. In addition, certain federal legislation such as the Competition Act and the Investment Canada Act could negatively affect the Corporation's business, financial condition and the market value of its Common Shares or its assets, particularly when undertaking, or attempting to undertake, acquisition or disposition activity.

Royalty Regimes

Changes to royalty regimes may negatively impact the Corporation's cash flows. There can be no assurance that the governments in the jurisdictions in which the Corporation has assets will not adopt new royalty regimes, or modify the existing royalty regimes, which may have an impact on the economics of the Corporation's projects. An increase in royalties would reduce the Corporation's earnings and could make future capital investments, or the Corporation's operations, less economic.

Hydraulic Fracturing

Implementation of new regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production volumes, adversely affecting the Corporation's financial position. The Corporation's operations are dependent upon the availability of water and its ability to dispose of produced water from drilling and production activities.

Hydraulic fracturing involves the injection of water, sand, and small amounts of additives under high pressure into tight rock formations that were previously unproductive to stimulate the production of oil, NGLs and natural gas. Concerns about seismic activity, including earthquakes, caused by hydraulic fracturing has resulted in regulatory authorities implementing additional protocols for areas that are prone to seismic activity or completely banning hydraulic fracturing in other areas. Any new laws, regulations, or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third-party or governmental claims, and could increase the Corporation's costs of compliance and doing business, as well as delay the development of oil, NGLs and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Restrictions or bans on hydraulic fracturing in the areas where the Corporation operates could result in the Corporation being unable to economically recover its oil and gas reserves which would result in a significant decrease in the value of the Corporation's assets.

Water is an essential component of the Corporation's drilling and hydraulic fracturing processes. Limitations or restrictions on the Corporation's ability to secure enough water (including limitations resulting from natural causes such as drought), could materially and adversely impact its operations. Severe drought conditions can result in local water authorities taking steps to restrict the use of water in their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If the Corporation is unable to obtain water to use in its operations from local sources, it may need to be obtained from new sources and transported to drilling sites, resulting in increased costs, which could have a material adverse effect on its financial condition, results of operations, and cash flows.

In addition, the Corporation must dispose of the fluids produced from oil, NGLs and natural gas production operations, including produced water, which it does directly or through the use of third-party vendors. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities.

Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated laws and regulations regarding waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by the Corporation or by commercial disposal well vendors that the Corporation may use from time to time to dispose of produced water. Increased regulation and attention given to

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induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and natural gas activities utilizing injection wells for produced water disposal. Any one or more of these developments may result in the Corporation or its vendors having to limit disposal well volumes, disposal rates and pressures or locations, or require the Corporation or its vendors to shut down or curtail the injection of produced water into disposal wells, which events could have a material adverse effect on the Corporation's business, financial condition, and results of operations.

Environmental

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial, and local laws and regulations. Environmental legislation provides for, among other things, the initiation and approval of new oil and natural gas projects, restrictions and prohibitions on the spill, release or emission of various substances produced in association with oil and natural gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment, and reclamation of well and facility sites. New environmental legislation at the federal and provincial levels may increase uncertainty among oil and natural gas industry participants as the new laws are implemented, and the effects of the new rules and standards are felt in the oil and natural gas industry.

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge. Although the Corporation believes that it is in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Abandonment and Reclamation Costs

The Corporation will need to comply with the terms and conditions of environmental and regulatory approvals and all legislation regarding the abandonment of its projects and reclamation of the project lands at the end of their economic life, which may result in substantial abandonment and reclamation costs. Any failure to comply with the terms and conditions of the Corporation's approvals and legislation may result in the imposition of fines and penalties, which may be material. Generally, abandonment and reclamation costs are substantial and, while the Corporation accrues a reserve in its financial statements for such costs in accordance with IFRS Accounting Standards, such accruals may be insufficient. It is not possible at this time to estimate abandonment and reclamation costs reliably since they will, in part, depend on future regulatory requirements. Changing legislative requirements may result in increased costs or accelerate the time in which abandonment and reclamation must occur. There can be no assurance that the Corporation will be able to satisfy its future abandonment and reclamation obligations. As a result of the prolonged downturn in the oil and gas industry, the number of orphan wells (wells licensed to insolvent parties) has increased. The cost of abandoning orphan wells has largely been funded by industry. Accordingly, the increase in the number of orphan wells could result in an increase in fees or assessments to other oil and gas producers, such as the Corporation, to fund the abandonment and reclamation of these orphan wells.

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Liability Management

The Alberta Energy Regulator ("AER") administers the Liability Management Framework (the "AB LMF") to manage liability for most conventional upstream oil and natural gas wells, facilities, and pipelines in Alberta. The province has transitioned from a prescriptive framework toward a more holistic approach to liability management. Alberta maintains an Orphan Fund, run by the Orphan Well Association ("OWA"), to cover the costs of suspending, abandoning, remediating, and reclaiming wells, facilities, or pipelines if a licensee or working interest participant becomes insolvent or is otherwise unable to meet its obligations. The Orphan Fund is financed through levies imposed on industry participants and provincial loans. In March 2025, the Alberta government approved a $144.45 million levy for the OWA's 2025/26 operating budget.

The Supreme Court of Canada's decision in Orphan Well Association v. Grant Thornton (the "Redwater decision") continues to shape Alberta's liability management regime. As a result of the Redwater decision, receivers and trustees can no longer avoid the AER's legislated authority to impose abandonment orders or require security deposits before approving licence transfers during insolvency proceedings. Insolvent estates can no longer disclaim assets that have reached the end of their productive lives to prioritize valuable assets without first satisfying abandonment and reclamation obligations. The burden of a defunct licensee's obligations first falls on its working interest partners; thereafter, the AER may direct the Orphan Fund to assume care and custody and accelerate cleanup of wells or sites which do not have a responsible owner.

Under the AB LMF, each licensee is required to meet mandatory annual spend targets for well closures and abandonments. In late 2025, the AER introduced mandatory annual closure spending requirements effective in 2026, reinforcing proactive liability reduction measures. The continued implementation of the AB LMF or other changes to the requirements of liability management programs may result in significant increases to the security that must be posted by licensees, increased and more frequent financial disclosure obligations, or may result in the denial of licence or permit transfers, which could impact the availability of capital to be spent by such licensees, which could in turn materially adversely affect the Corporation's business and financial condition. In addition, the liability management regime may prevent or interfere with the Corporation's ability to acquire or dispose of assets, as both the vendor and the purchaser of oil and natural gas assets must comply with the liability management programs for the applicable regulatory agency to allow for the transfer of such assets.

Climate Change Policy Risks

Global climate issues continue to attract public and scientific attention. Numerous reports, including reports from the Intergovernmental Panel on Climate Change, have engendered concern about the impacts of human activity, especially hydrocarbon combustion, on global climate issues. In turn, increasing public, government, and investor attention is being paid to global climate issues and to greenhouse gas ("GHG") emissions, including emissions of carbon dioxide and methane from the production and use of oil, liquids and natural gas. The majority of countries across the globe, including Canada and the United States, have agreed to reduce their carbon emissions in accordance with the Paris Agreement. At the 2025 United Nations Climate Change Conference (COP30) in Brazil, Canada reaffirmed its commitments to transitioning away from fossil fuels in line with the Paris Agreement.

Foreign and domestic governments continue to evaluate and implement policy, legislation and regulations focused on restricting GHG emissions and promoting adaptation to climate change and the transition to a low-carbon economy. Given the evolving nature of climate change policy and the control of GHG emissions and resulting requirements, including carbon taxes and carbon pricing schemes implemented by varying levels of government, it is expected that current and future climate change regulations will have the effect of increasing operating expenses, and, in the long-term, potentially reducing the demand for crude oil and natural gas and related products, resulting in a

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decrease in the Corporation's profitability and a reduction in the value of its assets. Claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under certain laws or that such energy companies provided misleading disclosure to the public and investors of current or future risks associated with climate change. Individuals, governmental authorities, or other organizations may make claims against oil and natural gas companies, including the Corporation, for alleged personal injury, property damage, or other potential liabilities. While the Corporation is not a party to any such litigation or proceedings, it could be named in actions making similar allegations. An unfavourable ruling in any such case could adversely affect the demand for and price of securities issued by the Corporation, impact its operations and have an adverse impact on its financial condition.

Due to long-term risks from environmental policy changes, regulations, legal challenges, and market shifts related to climate change, recent efforts have targeted the financial sector. Investment advisors, banks, pension funds, universities, and other institutional investors are engaging companies on climate action, using voting rights, and reallocating capital toward low-carbon assets while divesting from high-emission businesses. Certain stakeholders have also pressured insurance providers and commercial and investment banks to reduce or stop financing and providing insurance coverage to oil and natural gas and related infrastructure businesses and projects. The impact of such efforts requires the Corporation's management to dedicate significant time and resources to these climate change-related concerns, may adversely affect the Corporation's operations, the demand for and price of the Corporation's securities and may negatively impact the Corporation's cost of capital and access to the capital markets.

Climate-related regulations and reporting standards continue to evolve. In June 2023, the International Sustainability Standards Board issued two global disclosure standards, IFRS S1 and S2, to promote consistent, comparable, and reliable environmental reporting. In December 2024, the Canadian Sustainability Standards Board finalized similar Canadian Standards, CSDS 1 and CSDS 2. In December 2025, the ISSB announced targeted amendments to IFRS S2; whether the Canadian Standards will be revised remains uncertain. Meanwhile, in April 2025, due to significant changes in the global economic and geopolitical landscape, the Canadian Securities Administrators paused work on its own climate disclosure initiative, including Proposed National Instrument 51-107. If the Corporation is not able to meet future climate-related reporting requirements of regulators or current and future expectations of investors, insurance providers, or other stakeholders, its business and ability to attract and retain skilled employees, obtain regulatory permits, licences, registrations, approvals, and authorizations from various governmental authorities, and raise capital may be adversely affected.

Physical Risks from Climate Change

The potential physical risks resulting from climate change are long-term in nature and associated with a high degree of uncertainty regarding the timing, scope, and severity of potential impacts. Many experts believe global climate change could increase extreme variability in weather patterns such as increased frequency of severe weather, rising mean temperature and sea levels, and long-term changes in precipitation patterns. Extreme hot and cold weather, heavy snowfall, heavy rainfall, drought and wildfires may restrict the Corporation's ability to access its properties and cause operational difficulties, including damage to equipment and infrastructure. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions. Certain of the Corporation's assets are proximate to forests and rivers, and a wildfire or flood may lead to significant downtime and/or damage to the Corporation's assets or cause disruptions to the production and transport of its products or the delivery of goods and services in its supply chain.

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Carbon Pricing Risk

In Canada, the federal and certain provincial governments have implemented legislation aimed at incentivizing the use of alternative fuels and, in turn, reducing carbon emissions. The taxes placed on carbon emissions may have the effect of decreasing the demand for oil and natural gas products and, at the same time, increasing the Corporation's operating expenses, each of which may have a material adverse effect on the Corporation's profitability and financial condition. Further, the imposition of carbon taxes puts the Corporation at a disadvantage with its counterparts who operate in jurisdictions where there are less costly carbon regulations.

Anti-Greenwashing Legislation

Amendments to the Competition Act introduced in June 2024 prohibit companies from making false or misleading environmental claims. The new rules require businesses making environmental claims about products or business practices to substantiate their statements with "adequate and proper tests" or internationally recognized methodologies. While private rights of action for greenwashing came into effect in June 2025, the Budget 2025 Implementation Act, No. 1 subsequently removed this access and clarified substantiation requirements to address unintended consequences. Despite these improvements, the regulatory landscape continues to evolve and penalties for non-compliance remain significant, including up to the greater of $10 million for a first order, $15 million for subsequent orders, or 3% of global annual revenues. Companies making voluntary environmental disclosures, including the Corporation, face ongoing risk of liability and reputational harm.

Inflation, Cost Management and Rising Interest Rates

A failure to secure the services and equipment necessary for the Corporation's operations for the expected price, on the expected timeline, or at all, may have an adverse effect on the Corporation's financial performance and cash flows.

The Corporation's operating costs could escalate and become uncompetitive due to supply chain disruptions, inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, and additional government intervention through stimulus spending or additional regulations. The Corporation's inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on its financial performance and cash flows.

The cost or availability of oil and gas field equipment may adversely affect the Corporation's ability to undertake exploration, development, and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including drilling rigs, geological and geophysical services, engineering and construction services, major equipment items for infrastructure projects and construction materials generally. These materials and services may not be available when required at reasonable prices. A failure to secure the services and equipment necessary to the Corporation's operations for the expected price, on the expected timeline, or at all, may have an adverse effect on the Corporation's financial performance and cash flows.

Although interest rates have begun to decline from their recent peaks, they remained elevated for an extended period as central banks implemented measures to curb inflation. Higher borrowing costs during these periods may affect the Corporation's financing expenses and reduce returns on capital projects. Sustained periods of elevated interest rates can slow economic growth, reduce energy demand, depress commodity prices, and limit industry activity. The duration and combined impact of inflationary pressures and interest rate volatility on energy demand, commodity pricing, and the Corporation's operations remain uncertain.

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Seasonality

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable which prevents, delays, or makes operations more difficult. Consequently, municipalities and provincial transportation departments may enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Road bans and other restrictions generally result in a reduction of drilling and exploratory activities and may also result in the shut-in of some of the Corporation's production if not otherwise tied-in. Certain landowners could also restrict access to well sites during the planting, growing and harvesting seasons.

Variations in Foreign Exchange Rates and Interest Rates

World oil and natural gas prices are quoted in United States dollars. The Canadian/United States dollar exchange rate, which fluctuates over time, consequently affects the price received by Canadian producers of oil and natural gas. Material increases in the value of the Canadian dollar relative to the United States dollar will negatively affect the Corporation's production revenues. Accordingly, exchange rates between Canada and the United States could affect the future value of the Corporation's reserves as determined by independent evaluators. Although a low value of the Canadian dollar relative to the United States dollar may positively affect the price the Corporation receives for its oil and natural gas production, it could also result in an increase in the price for certain goods used for the Corporation's operations, which may have a negative impact on the Corporation's financial results.

To the extent that the Corporation engages in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which the Corporation may contract. In addition, an increase in interest rates could negatively impact the market price of the Common Shares of the Corporation.

Substantial Capital Requirements

The Corporation anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As future capital expenditures will be financed out of cash generated from operations, possible borrowings and possible future equity sales, the Corporation's ability to do so is dependent on, among other factors: the overall state of the capital markets; any applicable credit ratings; commodity prices; interest rates; royalty rates; tax burden due to current and future tax laws; and investor appetite for investments in the energy industry and the Corporation's securities in particular. To the extent that external sources of capital become limited, unavailable or available only on onerous terms, the Corporation's ability to invest and to maintain existing assets and to undertake or complete future drilling programs may be impaired, and its assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result.

Further, if the Corporation's revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. The conditions in, or affecting, the oil and natural gas industry have negatively impacted the ability of oil and natural gas companies, including the Corporation, to access additional financing and/or the cost thereof. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. The Corporation may be required to seek additional equity financing on terms that are highly dilutive to existing Shareholders. The inability of the Corporation to access sufficient capital for its operations could have a material adverse effect on the Corporation's business financial condition, results of operations and prospects.

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Additional Funding Requirements

The Corporation's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times and, from time to time, the Corporation may require additional financing in order to carry out its oil and natural gas acquisition, exploration and development activities. Failure to obtain financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce its operations. Due to the conditions in the oil and natural gas industry and/or global economic and political volatility, the Corporation may, from time to time, have restricted access to capital and increased borrowing costs. The current conditions in the oil and natural gas industry have negatively impacted the ability of oil and natural gas companies to access, or the cost of, additional financing.

As a result of global economic and political conditions and the domestic lending landscape, the Corporation may, from time to time, have restricted access to capital and increased borrowing costs. Failure to obtain suitable financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Corporation's revenues from its reserves decrease because of lower oil and natural gas prices or otherwise, it will affect the Corporation's ability to expend the necessary capital to replace its reserves or to maintain its production. To the extent that external sources of capital become limited, unavailable or available on onerous terms, the Corporation's ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be affected materially and adversely as a result. In addition, the future development of the Corporation's petroleum properties may require additional financing and there are no assurances that such financing will be available or, if available, will be available upon acceptable terms. Alternatively, any available financing may be highly dilutive to existing Shareholders. Failure to obtain any financing necessary for the Corporation's capital expenditure plans may result in a delay in development or production on the Corporation's properties.

Asset Concentration

The Corporation's producing properties are geographically concentrated. As a result, to the extent demand for and costs of personnel, equipment, power, services, and resources in such geographic area are high it could result in a delay or inability to secure the personnel, equipment, power, services, and resources. Any delay or inability to secure the personnel, equipment, power, services, and resources could result in crude oil, NGLs and natural gas production volumes being below the Corporation's forecasted production volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on the Corporation's financial conditions, results of operations, cash flow, and profitability. As a result of this concentration, the Corporation may be disproportionately exposed to the impact of delays or interruptions of operations or production in this area caused by external factors such as governmental regulation, provincial politics, market limitations, supply shortages, or extreme weather-related conditions.

Issuance of Debt

From time to time, the Corporation may enter into transactions to acquire assets or shares of other entities. These transactions may be financed in whole, or in part, with debt, which may increase the Corporation's debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, the Corporation may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither the Corporation's articles nor its by-laws limit the amount of indebtedness that the Corporation may incur. The level of the Corporation's indebtedness from time to time could impair the Corporation's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

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Risk Management Contracts

From time to time, the Corporation may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline. However, to the extent that the Corporation engages in price risk management activities to protect itself from commodity price declines, it may also be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, the Corporation’s risk management contracts may expose it to the risk of financial loss in certain circumstances, including instances in which, production falls short of the contracted volumes or prices fall significantly lower than projected; there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the arrangement; counterparties to the arrangements or other price risk management contracts fail to perform under those arrangements; or a sudden unexpected event materially impacts oil and natural gas prices.

Similarly, from time to time, the Corporation may enter into agreements to fix the exchange rate of Canadian to United States dollars or other currencies in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to other currencies. However, if the Canadian dollar declines in value compared to such fixed currencies, the Corporation will not benefit from the fluctuating exchange rate.

Title to and Right to Produce from Assets

The Corporation’s actual title to and interest in its properties, and its right to produce and sell the oil and natural gas therefrom, may vary from the Corporation’s records. In addition, there may be valid legal challenges or legislative changes that affect the Corporation’s title to and right to produce from its oil and natural gas properties, which could impair the Corporation’s activities and result in a reduction of the revenue received by the Corporation.

If a defect exists in the chain of title or in the Corporation’s right to produce, or a legal challenge or legislative change arises, it is possible that the Corporation may lose all, or a portion of, the properties to which the title defect relates and/or its right to produce from such properties. This may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects.

Reserves Estimates

There are numerous uncertainties inherent in estimating reserves and the future cash flows attributed to such reserves. The reserves and associated cash flow information set forth in this document are estimates only. Generally, estimates of economically recoverable oil and natural gas reserves (including the breakdown of reserves by product type) and the future net cash flows from such estimated reserves are based upon a number of variable factors and assumptions, such as, but not limited to: historical production from properties; production rates; ultimate reserve recovery; timing and amount of capital expenditures; marketability of oil and natural gas; royalty rates; and the assumed effects of regulation by governmental agencies and future operating costs (all of which may vary materially from actual results).

For those reasons, estimates of the economically recoverable oil 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. The Corporation’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates and such variations could be material.

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The estimation of proved reserves that may be developed and produced in the future is often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas are often estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

In accordance with applicable securities laws, the Corporation's independent reserves evaluator has used forecast prices and costs in estimating the reserves and future net cash flows as summarized herein. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived from the Corporation's oil and natural gas reserves will vary from the estimates contained in the reserve evaluation, and such variations could be material. The reserve evaluation is based in part on the assumed success of activities the Corporation intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom and contained in the reserve evaluation will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation. The reserve evaluation is effective as of a specific effective date and, except as may be specifically stated, has not been updated and therefore does not reflect changes in the Corporation's reserves since that date.

Geopolitical Risks

The marketability and price of oil and natural gas that may be acquired or discovered by the Corporation is and will continue to be affected by political events throughout the world that cause disruptions in the supply of

oil. Conflicts, or conversely peaceful developments, arising outside of Canada, including changes in political regimes or parties in power, may have a significant impact on the price of crude oil and natural gas. Any particular event could result in a material decline in prices and therefore result in a reduction of the Corporation's net production revenue.

The level of geo-political risk escalates at certain points in time. While the specific impact on the global economy would depend on the nature of the event, in general, any major event could result in instability and volatility. Current areas of concern include: Russia's military invasion of Ukraine and the absence of a comprehensive peace settlement; the broader Israeli-Hamas conflict, including escalations between Israel, the United States and Iran; ongoing Houthi attacks on Red Sea shipping; the fall of the Syrian Assad regime and uncertainty regarding the transitional government; U.S. military action in Venezuela and the potential impact of increased U.S. access to Venezuelan crude oil reserves on Canadian export demand; and activism and political upheaval globally.

Impact of U.S. Legislative and Regulatory Policies

The Corporation's business is exposed to risks arising from changes in international trade policy, including the imposition of tariffs, trade barriers, or other protectionist measures. Since February 2025, the U.S. administration has announced, suspended, and reimposed various tariffs on Canadian imports, including tariffs on Canadian energy imports. In March 2025, the United States imposed a series of tariffs on goods imported from Canada and other countries, triggering retaliatory measures by Canada and several trading partners. The U.S. also imposed 25% "national security" tariffs under Section 232 of the Trade Expansion Act of 1962 on steel, aluminum, copper products, autos, auto parts, and certain other goods, which have no USMCA exemption. On February 20, 2026, the U.S.

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Supreme Court held that the Trump administration lacked legal authority to impose certain tariffs under the International Emergency Economic Powers Act. In response, the administration imposed a temporary global tariff under the Trade Act of 1974 and indicated its intention to pursue alternative trade measures. The Canada-United States-Mexico Agreement is scheduled for comprehensive joint review in July 2026, which may result in modifications to the trade framework governing cross-border energy commerce. The imposition, continuation, or expansion of tariffs on Canadian energy exports could reduce the realized prices for the Corporation's production, increase costs for imported goods and services used in the Corporation's operations, and disrupt North American commodity markets. Retaliatory trade measures by Canada could further increase costs and uncertainty. See "Industry Conditions".

There is uncertainty regarding U.S. tariffs and support for existing treaty and trade relationships, including with Canada. Furthermore, there is a risk that tariffs imposed by the U.S. on other countries will trigger a broader global trade war, which could impose additional costs on the Corporation, decrease U.S. demand for the Corporation's products, or otherwise negatively impact the Corporation. Implementation by the U.S. government of new legislative or regulatory policies could impose additional costs on Tuktu, decrease U.S. demand for the Corporation's products, or otherwise negatively impact the Corporation, which may have a material adverse effect on Tuktu's business, financial condition and operations.

Insurance

The Corporation's involvement in the exploration for and development of oil and natural gas properties may result in the Corporation becoming subject to liability for pollution, blowouts, leaks of sour gas, property damage, personal injury or other hazards. Although the Corporation maintains insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, the Corporation may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds available to the Corporation.

The occurrence of a significant event that the Corporation is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

The Corporation's insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, policy limits and/or deductibles for certain insurance policies can vary substantially. In some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Significantly increased costs could lead the Corporation to decide to reduce or possibly eliminate coverage. In addition, insurance is purchased from several third-party insurers, often in layered insurance arrangements, some of whom may discontinue providing insurance coverage for their own policy or strategic reasons. Should any of these insurers refuse to continue to provide insurance coverage, the Corporation's overall risk exposure could be increased, and the Corporation could incur significant costs.

Non-Governmental Organizations

The oil and natural gas exploration, development and operating activities conducted by the Corporation may at times be subject to public opposition. Such public opposition could expose the Corporation to the risk of higher costs, delays or even project cancellations due to increased pressure on governments and regulators by special interest groups including Indigenous groups, landowners, environmental interest groups (including those opposed to oil and natural gas production operations)

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and other non-governmental organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support from the federal, provincial or municipal governments, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses, and direct legal challenges, including the possibility of climate-related litigation. There is no guarantee that the Corporation will be able to satisfy the concerns of the special interest groups and non-governmental organizations and attempting to address such concerns may require the Corporation to incur significant and unanticipated capital and operating expenditures.

Reputational Risk Associated with the Corporation's Operations

The Corporation's business, operations or financial condition may be negatively impacted because of any negative public opinion towards the Corporation or as a result of any negative sentiment toward, or in respect of, the Corporation's reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups' negative portrayal of the industry in which the Corporation operates as well as their opposition to certain oil and natural gas projects. Potential impacts of negative public opinion or reputational issues may include delays or interruptions in operations, legal or regulatory actions or challenges, blockades, increased regulatory oversight, reduced support for, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses and increased costs and/or cost overruns. The Corporation's reputation and public opinion could also be impacted by the actions and activities of other companies operating in the oil and natural gas industry, particularly other producers, over which the Corporation has no control. Similarly, the Corporation's reputation could be impacted by negative publicity related to loss of life, injury or damage to property and environmental damage caused by the Corporation's operations. In addition, if the Corporation develops a reputation of having an unsafe work site, it may impact the ability of the Corporation to attract and retain the necessary skilled employees and consultants to operate its business. Opposition from special interest groups opposed to oil and natural gas development and the possibility of climate related litigation against governments and hydrocarbon companies may impact the Corporation's reputation.

Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, regulatory and legal risks, among others, must all be managed effectively to safeguard the Corporation's reputation. Damage to the Corporation's reputation could result in negative investor sentiment towards the Corporation, which may result in limiting the Corporation's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Corporation's securities.

Changing Investor Sentiment

There are several factors that, including the effects of the use of hydrocarbons on climate change, the impact of oil and natural gas operations on the environment, environmental damage relating to spills of petroleum products during production and transportation and Indigenous rights, have affected certain investors' sentiments towards investing in the oil and natural gas industry. As a result of these concerns, some institutional, retail and governmental investors have announced that they no longer are willing to fund or invest in oil and natural gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Board of Directors, management, and employees of the Corporation. Failing to implement the policies and practices, as requested by institutional investors, may result in such investors reducing their investment in the Corporation, or not investing in the Corporation at all. Any reduction in the investor base interested or willing to invest in the oil and natural gas industry and more specifically, the Corporation, may result in limiting the Corporation's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Corporation's securities even if the Corporation's operating results, underlying asset values or prospects have not changed.

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Indigenous Land and Rights Claims

Opposition by Indigenous groups to the conduct the Corporation's operations, development, or exploratory activities in any of the jurisdictions in which the Corporation conducts business may negatively impact it in terms of public perception, diversion of management's time and resources, legal and other advisory expenses, and could adversely impact the Corporation's progress and ability to explore and develop properties.

Some Indigenous groups have established or asserted Indigenous treaty, title, and rights to portions of Canada. Although there are no Indigenous and treaty rights claims on lands where the Corporation operates, no certainty exists that any lands currently unaffected by claims brought by Indigenous groups will remain unaffected by future claims. Such claims, if successful, could have a material adverse impact on its operations or pace of growth.

The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain circumstances, accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of ongoing litigation. The fulfillment of the duty to consult Indigenous people and any associated accommodations may adversely affect the Corporation's ability to, or increase the timeline to, obtain or renew, permits, leases, licences, and other approvals, or to meet the terms and conditions of those approvals. For example, a recent British Columbia Supreme Court decision determined that the cumulative impacts of government sanctioned industrial development on the traditional territories of a First Nations group in northeast British Columbia breached that group's treaty rights. Going forward, this decision may have significant impacts on the regulation of industrial activities in northeast British Columbia. Further, it may lead to similar claims of cumulative effects across Canada in other areas covered by numbered treaties. The long-term impacts of and associated risks of the decision on the Canadian oil and natural gas industry and the Corporation remain uncertain.

In addition, the federal government has introduced legislation to implement the UNDRIP. Other Canadian jurisdictions, including British Columbia, have also introduced, or passed similar legislation, or begun considering the principles and objectives of UNDRIP, or may do so in the future. The means and timelines associated with UNDRIP's implementation by government is uncertain; additional processes may be created or legislation amended or introduced associated with project development and operations, further increasing uncertainty with respect to project regulatory approval timelines and requirements. See "Industry Conditions – Indigenous Rights".

Dilution

The Corporation may issue additional Common Shares or other dilutive securities, diluting current Shareholders. The Corporation may make future acquisitions or enter into financings or other transactions involving the issuance of securities of the Corporation, which may be dilutive to Shareholders.

Management of Growth

The Corporation may be subject to growth-related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Corporation to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expand, train and manage its employee base. If the Corporation is unable to deal with this growth, it may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Expiration of Licenses and Leases

The Corporation's properties are held in the form of licenses and leases and working interests in licenses and leases. If the Corporation, or the holder of the license or lease, fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each license or lease will be met. The termination or expiration of the Corporation's licenses or leases or the working interests relating to a license or lease and the associated abandonment and reclamation obligations may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Dividends

The Corporation does not pay any dividends on its outstanding shares. Payment of dividends in the future will be dependent on, among other things, cash flow, results of operations, financial condition of the Corporation, the need for funds to finance ongoing operations and other considerations, as the Board of Directors considers relevant.

Litigation

The Corporation is not subject to any ongoing litigation. However, from time to time, the Corporation may be subject, directly or indirectly, to litigation arising out of its operations and the regulatory environments in its areas of operations. Damages claimed under litigation in the future may be material or may be indeterminate. The outcome of future proceedings cannot be predicted with certainty and may be determined adversely to Tuktu and as a result, could have a material adverse effect on the Corporation's assets, liabilities, business, financial condition and results of operations. In addition, the Corporation may be required to incur significant expenses or devote significant resources to defending against litigation. Adverse publicity surrounding litigation could also have a material effect on the Corporation's business.

Intellectual Property Litigation

Due to the rapid development of oil and natural gas technology, in the normal course of the Corporation's operations, the Corporation may become involved in, named as a party to, or be the subject of, various legal proceedings in which it is alleged that the Corporation has infringed the intellectual property rights of others or which the Corporation initiates against others it believes are infringing upon its intellectual property rights. The Corporation's involvement in intellectual property litigation could result in significant expense, adversely affecting the development of its assets or intellectual property or diverting the efforts of its technical and management personnel, whether or not such litigation is resolved in the Corporation's favor. In the event of an adverse outcome as a defendant in any such litigation, the Corporation may, among other things, be required to: pay substantial damages and/or cease the development, use, sale or importation of processes that infringe upon other patented intellectual property; expend significant resources to develop or acquire non-infringing intellectual property; discontinue processes incorporating infringing technology; or obtain licenses to the infringing intellectual property.

However, the Corporation may not be successful in such development or acquisition, or such licenses may not be available on reasonable terms. Any such development, acquisition or license could require the expenditure of substantial time and other resources and could have a material adverse effect on the Corporation's business and financial results.

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Breach of Confidentiality

While discussing potential business relationships or other transactions with third parties, the Corporation may disclose confidential information relating to its business, operations, or affairs. Although confidentiality agreements are generally signed by third parties prior to the disclosure of any confidential information, a breach could put the Corporation at competitive risk and may cause significant damage to its business. The harm to the Corporation's business from a breach of confidentiality cannot presently be quantified but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, the Corporation will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, to prevent or mitigate any damage to its business that such a breach of confidentiality may cause.

Income Taxes

The Corporation files all required income tax returns and believes that it is in full compliance with the provisions of the Tax Act and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment of the Corporation, whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable.

Income tax laws relating to the oil and natural gas industry, such as the treatment of resource taxation or dividends, may in the future be changed or interpreted in a manner that adversely affects the Corporation. Furthermore, tax authorities having jurisdiction over the Corporation may disagree with how the Corporation calculates its income for tax purposes or could change administrative practices to the Corporation's detriment.

Third Party Credit Risk

The Corporation may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Corporation, such failures may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry, generally, and of the Corporation's joint venture partners may affect a joint venture partner's willingness to participate in the Corporation's ongoing capital program, potentially delaying the program and the results of such program until the Corporation finds a suitable alternative partner. To the extent that any of such third parties go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in the Corporation being unable to collect all or a portion of any money owing from such parties. Any of these factors could materially adversely affect the Corporation's financial and operational results.

Operational Dependence

Other companies operate some of the assets in which the Corporation has an interest. The Corporation has limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Corporation's financial performance. The Corporation's return on assets operated by others depends upon a number of factors that may be outside of the Corporation's control, including, but not limited to, the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices. In addition, due to volatile commodity prices, companies that operate some of the assets in which the Corporation has an interest may encounter

financial difficulty, which could impact their ability to fund and pursue capital expenditures, carry out their operations in a safe and effective manner and satisfy regulatory requirements with respect to abandonment and reclamation obligations. If such companies fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations, the Corporation may be required to satisfy such obligations and to seek reimbursement from such companies.

Conflict of Interest

Certain directors or officers of the Corporation may also be directors or officers of other oil and natural gas companies and as such may, in certain circumstances, have a conflict of interest. Conflicts of interest, if any, will be subject to and governed by procedures prescribed by the ABCA which require a director or officer of a corporation who is a party to, or is a director or an officer of, or has a material interest in any person who is a party to, a material contract or proposed material contract with the Corporation to disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the ABCA.

Reliance on a Skilled Workforce and Key Personnel

The operations and management of the Corporation require the recruitment and retention of a skilled workforce, including engineers, technical personnel, and other professionals. The loss of key members of such workforce, or a substantial portion of the workforce could result in the failure to implement the Corporation's business plans which could have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Corporation will be able to continue to attract and retain all personnel necessary for the development and operation of its business. The Corporation does not have any key personnel insurance in effect. Contributions of the existing management team to the immediate and near-term operations of the Corporation are likely to be of central importance. In addition, certain of the Corporation's current employees may have significant institutional knowledge that must be transferred to other employees prior to their departure from the workforce. If the Corporation is unable to: (i) retain current employees; (ii) successfully complete effective knowledge transfers; and/or (iii) recruit new employees with the requisite knowledge and experience, the Corporation could be negatively impacted. In addition, the Corporation could experience increased costs to retain and recruit these professionals.

Information Technology Systems and Cyber-Security

The Corporation is increasingly dependent upon the availability, capacity, reliability and security of our information technology infrastructure, and our ability to expand and continually update this infrastructure, to conduct daily operations. The Corporation depends on various information technology systems to estimate reserve quantities, process, and record financial data, manage the Corporation's land base, manage financial resources, analyze seismic information, administer contracts with operators and lessees and communicate with employees and third-party partners.

Further, the Corporation is subject to a variety of information technology and system risks as a part of its operations including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Corporation's information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary, or proprietary information, interruption to communications or operations or disruption to business activities or the Corporation's competitive position. In addition, cyber phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, and credit card details (and money) by disguising as a

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trustworthy entity in an electronic communication, have become more widespread and sophisticated in recent years. If the Corporation becomes a victim to a cyber phishing attack it could result in a loss or theft of the Corporation's financial resources or critical data and information or could result in a loss of control of the Corporation's technological infrastructure or financial resources. The Corporation's employees are often the targets of such cyber phishing attacks, as they are and will continue to be targeted by parties using fraudulent "spoof" emails to misappropriate information or to introduce viruses or other malware through "Trojan horse" programs to the Corporation's computers. These emails appear to be legitimate emails, but direct recipients to fake websites operated by the sender of the email or request recipients to send a password or other confidential information through email or to download malware.

The Corporation maintains policies and procedures that address and implement employee protocols with respect to electronic communications and electronic devices and conducts annual cyber-security risk assessments. The Corporation also employs encryption protection of its confidential information, all computers and other electronic devices. Despite the Corporation's efforts to mitigate such cyber phishing attacks through education and training, cyber phishing activities remain a serious problem that may damage its information technology infrastructure. The Corporation applies technical and process controls in line with industry-accepted standards to protect its information, assets, and systems, including a written incident response plan for responding to a cyber-security incident. However, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology services, or breaches of information security, could have a negative effect on the Corporation's performance and earnings, as well as its reputation, and any damages sustained may not be adequately covered by the Corporation's current insurance coverage, or at all. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Corporation's business, financial condition, and results of operations.

Social Media

Increasingly, social media is used as a vehicle to carry out cyber phishing attacks. Information posted on social media sites, for business or personal purposes, may be used by attackers to enter the Corporation's systems and obtain confidential information. There are significant risks that the Corporation may not be able to properly regulate social media use and preserve adequate records of business activities and client communications conducted using social media platforms.

Artificial Intelligence

The use by the Corporation's employees of artificial intelligence tools or technology can adversely impact the business by posing risks to confidential or proprietary information and could give rise to legal actions or reputational damage, or otherwise adversely affect the Corporation's business. The Corporation's workforce may use artificial intelligence tools or technology, which may result in the exposure of the Corporation's confidential or proprietary information to unauthorized third parties and the misuse of the Corporation's intellectual property. Use of artificial intelligence tools or technology may also result in claims against the Corporation alleging violation of third-party intellectual property rights. Use of artificial intelligence tools or technology may also result in inaccurate results that could cause mistakes in the Corporation's decision-making or other business activities, which may have an adverse impact on the Corporation's business and results of operations. Further, there is no guarantee that the Corporation's training and enforcement of procedures governing the use of artificial intelligence will be adequate to safeguard against the unauthorized use of artificial intelligence tools or technology.

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Expansion into New Activities

The operations and expertise of the Corporation's management are currently focused primarily on oil and natural gas production, exploration, and development in the Western Canada Sedimentary Basin. In the future, the Corporation may acquire or move into new industry related activities or new geographical areas and may acquire different energy-related assets; as a result, the Corporation may face unexpected risks or, alternatively, its exposure to one or more existing risk factors may be significantly increased, which may in turn result in the Corporation's future operational and financial conditions being adversely affected.

Forced or Child Labour in Supply Chains

In May 2023, the Fighting Against Forced Labour and Child Labour in Supply Chains Act was passed and came into force on January 1, 2024. Pursuant to the new legislation, any company that is subject to the reporting requirements, including the Corporation, is required to file an annual report with respect to its supply chains. In late 2024, the federal government signalled its intention to create a new and more onerous supply chain due diligence regime overseen by a new oversight agency, whereby reporting entities would be required to scrutinize their supply chains for human rights risks and take action to resolve any such risks. Although the Corporation is currently unaware of any forced or child labour within its supply chains, heightened scrutiny of Canadian companies could reveal risks or instances of such practices in a supply chain connected to the Corporation, potentially harming its reputation. In addition, complying with any new legislative requirements related to due diligence of its supply chains will increase the Corporation's costs and regulatory burdens.

Natural Disasters, Wars, Civil Unrest, Pandemics and Other Disruptions and Dislocations

Upon the occurrence of a natural disaster, or upon an incident of war (including the wars in Ukraine, Lebanon and Iran), riot or civil unrest, the impacted country, province, or region may not efficiently and quickly recover from such event, which could have a materially adverse effect on the Corporation, its customers, and/or either of their businesses or operations. In addition, terrorist attacks, public health crises including epidemics, pandemics or outbreaks of new infectious disease or viruses, domestic and global trade disruptions, infrastructure disruptions, civil disobedience or unrest, natural disasters, national emergencies, acts of war, technological attacks and related events can result in volatility and disruption to local and global supply chains, operations, mobility of people and the financial markets, which could result in a significant reduction in economic activity in Canada and internationally along with a drop in demand for oil and natural gas, as well as affect interest rates, credit ratings, credit risk, inflation, business, financial conditions, results of operations and other factors relevant to the Corporation, its customers, and/or either of their businesses or operations, which may have a material adverse effect on the Corporation's reputation, business, financial conditions or operations and could aggravate the other risk factors identified herein.

Evolving Corporate Governance, Sustainability and Reporting Framework

The Corporation's business is subject to evolving corporate governance and public disclosure regulations that have increased both compliance costs and the risk of noncompliance, which could have an adverse effect on the price of the Corporation's securities. The Corporation is subject to changing rules and regulations promulgated by several governmental and self-regulated organizations, including the Canadian Securities administrators, the TSXV and the Financial Accounting Standards Board. These rules and regulations continue to evolve in scope and complexity making compliance more difficult and uncertain. Further, the Corporation's efforts to comply with these and other new and existing rules and regulations have resulted in, and are likely to continue to result in, increased general and administrative expenses and a diversion of management time and attention from revenue-generating activities to compliance activities.

Tuktu Resources Ltd.
2026 Annual Information Form

Geopolitical Events

The Corporation's business may be adversely affected by recent geopolitical events and decisions made in Canada, the United States, China, Europe and elsewhere. The current war in Ukraine and the international response has, and may continue to have, potential wide-ranging consequences for global market volatility and economic conditions, including energy and commodity prices, which may, in turn, increase inflationary pressures and interest rates. Certain countries, including Canada and the United States, have imposed strict financial and trade sanctions against Russia, which have, and may continue to have, far-reaching effects on the global economy and energy and commodity prices. The short, medium, and long-term implications of the war in Ukraine are difficult to predict with any certainty at this time and there remains uncertainty relating to the potential direct and indirect impact of the war on the Corporation, and it could have a material and adverse effect on its business, financial condition and results of operations. Depending on the extent, duration, and severity of the war, it may have the effect of heightening many of the other risks described herein, including, without limitation, the risks relating to the Corporation's exposure to commodity prices; the successful completion of the Corporation's growth and expansion projects, including the expected return on investment thereof; supply chains and the Corporation's ability to obtain required equipment, materials or labour; cybersecurity risks; inflationary pressures; and restricted access to capital and increased borrowing costs as a result of increased interest rates.

Management Transition and Key Person Risk

During the second half of 2025 and early 2026, the Corporation experienced significant management transition. Tim de Freitas ceased serving as President and Chief Executive Officer in September 2025, and Gregory Feltham, Kent Busby, Mark Smith, and Sumir Saini also departed the Corporation during this period. Jeremy Hodder was appointed President and Chief Executive Officer in October 2025, and Craig Wall was appointed Chief Financial Officer in February 2026. The Corporation is substantially dependent on the services and performance of its current management team, which has been in place for a limited period. There can be no assurance that the Corporation will be able to retain its current management team or, if necessary, attract qualified replacements. The loss of any member of the current management team, particularly during this transition period, could have a material adverse effect on the Corporation's operations, strategic direction, and financial condition. See "General Development of the Business."

Governance Uncertainty and Shareholder Activism

In October 2025, the Corporation received a requisition from a group of shareholders holding approximately 31% of the Corporation's outstanding Common Shares, demanding a special meeting to replace the Corporation's Board of Directors. The special meeting was held on January 15, 2026, and the dissident resolution was defeated. While the matter has been resolved, the Corporation may be subject to future shareholder activism campaigns, proxy contests, or other governance challenges. Responding to such campaigns can be costly and time-consuming, may divert the attention of the Board of Directors and management from the Corporation's business, and could result in uncertainty regarding the Corporation's strategic direction. There can be no assurance that future governance challenges will not occur or that such challenges would not be successful.

Asset Concentration – Monarch

The Corporation's current strategy concentrates its primary operational and development focus on the Monarch (Banff) oil play in southern Alberta. While the Corporation continues to hold other properties, including the Quaich, Pincher Creek, and Eastern Alberta assets, its growth strategy is substantially dependent on the successful development of the Monarch area. If the Monarch play does not perform as anticipated, whether due to unfavourable geological conditions, adverse commodity prices,

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regulatory obstacles, or other factors, the Corporation's results of operations and financial condition could be materially adversely affected. Concentration of operations in a single area also increases the Corporation's exposure to localized risks, including weather events, infrastructure disruptions, and regulatory changes affecting that specific area.

Horizontal Well Execution and Exploration Risk

In Q1 2025, the Corporation drilled and completed its first horizontal well (16-20) in the Monarch area. The well did not achieve commercial production rates and was subsequently shut-in. The Corporation's exploration and development activities are inherently uncertain and involve significant risk, including the risk that wells will be unproductive, that geological conditions will differ from expectations, and that completion techniques will not achieve anticipated results. The failure of the Corporation's first horizontal well demonstrates the execution risk associated with exploration and development programs. There can be no assurance that future wells will be successful or that the Corporation will be able to develop its resource base economically. See "Description of the Business — Oil and Natural Gas Properties — Monarch."

ADDITIONAL INFORMATION

Additional information relating to the Corporation may be found on Tuktu's SEDAR+ profile at www.sedarplus.ca, including directors' and officers' remuneration and indebtedness, principal holders of the Corporation's securities and securities authorized for issuance under equity compensation plans which is contained in the Corporation's information circular for the Corporation's most recent annual meeting of shareholders of the Corporation.

Additional financial information is contained in the Financial Statements and MD&A for the Corporation's most recently completed financial year.

Tuktu Resources Ltd.
2026 Annual Information Form

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APPENDIX A

51-101F2: REPORT ON RESERVES DATA BY DELOITTE LLP

To the Board of Directors of Tuktu Resources Ltd. (the "Corporation"):

We have evaluated the Corporation's reserves data as at December 31, 2025. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2025 estimated using forecast prices and costs.
The reserves data are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved + probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated for the year ended December 31, 2025, and identifies the respective portions thereof that we have evaluated and reported on to the Corporation's Board of Directors:

Independent Qualified Reserves Evaluator	Effective Date of Evaluation Report	Location of Reserves	Net Present Value of Future Net Revenue $M (before income taxes, 10% discount rate)
			Audited	Evaluated	Reviewed	Total
Deloitte LLP	Dec. 31, 2025	Canada	n/a	$67,262	n/a	$67,262

In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
We have no responsibility to update our report referred to in paragraph 5 for events and circumstances occurring after the effective date of our report.
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above as of this 1st day of April, 2026:

(signed) "Lesley Mitchell"

Lesley Mitchell, P. Eng.

Partner

Deloitte LLP

A - 1

APPENDIX B

51-101F3: REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Tuktu Resources Ltd. (the “Corporation”) is responsible for the preparation and disclosure of information with respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.

Deloitte Canada LLP, an independent qualified reserves evaluator, has evaluated the Corporation’s reserves data. The report of the independent qualified reserves evaluator is presented below.

The Reserves Committee of the Board of Directors of the Corporation has:

(a) reviewed the Corporation’s procedures for providing information to the independent qualified reserves evaluator;
(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and
(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the Board of Directors has reviewed the Corporation’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved:

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
(b) the filing of Form 51-102F2 which is the report of the independent qualified reserves evaluator on the reserves data, contingent resources data, or prospective resources data; and the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

DATED as of this 21st day of April, 2026.

(signed) “Jeremy Hodder”
Jeremy Hodder
President and Chief Executive Officer

(signed) “Craig Wall”
Craig Wall
Chief Financial Officer

(signed) “Natalie Sweet”
Natalie Sweet
Director & Chair, Reserves Committee

(signed) “Kathleen Dixon”
Kathleen Dixon
Director

150907145 v3

AI assistant

Tuktu Resources Ltd. — Annual Report 2025

44385_rns_2026-04-23_fdb86b95-2bd9-47ef-9837-28b0522946dd.pdf

Table of Contents

APPENDICES

PRESENTATION OF INFORMATION

Abbreviations

Volume Conversions

Other

FORWARD-LOOKING INFORMATION AND STATEMENTS

Forward-Looking Information and Statements

SPECIFIED FINANCIAL MEASURES

OIL AND GAS INFORMATION

Levels of Certainty for Reported Reserves

Selected Oil and Gas Terms

CORPORATE STRUCTURE

CORPORATE HISTORY

Pre-Recapitalization (1994-2022)

Financial Year Ended December 31, 2023

Financial Year Ended December 31, 2024

Financial Year Ended December 31, 2025

Recent Events (Post Year-End)

2026 Corporate Strategy

Special Meeting Results

Appointment of Chief Financial Officer and Management Departures

Board Composition

Significant Acquisitions

DESCRIPTION OF BUSINESS

General

Business Plan

Oil and Natural Gas Properties

Monarch (formerly Penny)

Quaich

Pincher Creek

Eastern Alberta

Mineral Properties

Ruddock Creek (Irony)

Isintok (Copper Plateau)

Other Business information

Employees

Competitive Conditions

Commodity Price Cycles

Environmental Protection

Economic Dependence

Changes to Contracts

Environmental, Social and Governance ("ESG")

Environmental, Health and Safety Policies

Elements of our Environmental, Health and Safety Management System

System Monitoring

Training and Competency

Hazard Assessment

Risk Management

Incident Reporting and Investigation

Policy and Management Involvement

Emergency Response Management

Air

Water

Land and Reclamation

Reorganizations

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Disclosure of Reserves Data

Proved Undeveloped Reserves

SUMMARY OF PROVED UNDEVELOPED RESERVES

Probable Undeveloped Reserves

SUMMARY OF PROBABLE UNDEVELOPED RESERVES

Future Development Costs

Future Development Costs

Abandonment and Retirement Obligations

Significant Factors and Uncertainties

Other Oil and Gas Information

Oil and Gas Properties

Oil and Gas Wells

Acreage Information

Production Estimates

Production History

Capital Expenditures

Exploration and Development Activities

Commodity Price Risk Management

DIVIDENDS

DESCRIPTION OF CAPITAL STRUCTURE

Tuktu Resources Ltd. Annual Report 2025