Canadian Natural Resources : 2025 Annual Report (CNQ 2025 AIF March 25 2026)

CANADIAN NATURAL RESOURCES LIMITED ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2025 March 25, 2026

Annual Information Form

Table of Contents

Definitions and Abbreviations 2

Advisory 4

Corporate Structure 7

General Development of the Business 8

Description of the Business 10

1. Environmental Matters 11

2. Regulatory Matters 12

3. Competitive Factors 15

4. Risk Factors 15

Form 51-101F1 Statement of Reserves Data and Other Information 23

Selected Financial Information 51

Dividend History 52

Description of Capital Structure 52

Market for Securities 54

Directors and Executive Officers 55

Legal Proceedings and Regulatory Actions 59

Interest of Management and Others in Material Transactions 59

Transfer Agents and Registrar 59

Material Contracts 59

Interests of Experts 59

Audit Committee Information 59

Additional Information 61

Schedule "A" Form 51-101F2 Report On Reserves Data by Independent Qualified Reserves Evaluator or Auditor 62

Schedule "B" Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure 65

Schedule "C" Charter of the Audit Committee of the Board of Directors 67

Definitions and Abbreviations ADR abandonment, decommissioning and reclamation costs AOSP Athabasca Oil Sands Project API specific gravity measured in degrees on the American Petroleum Institute scale ARO asset retirement obligations bbl barrel bbl/d barrels per day Bcf billion cubic feet bitumen naturally occurring solid or semi-solid hydrocarbon, consisting mainly of heavier hydrocarbons that are too heavy or thick to flow at reservoir conditions, and recoverable at economic rates using thermal in-situ recovery or conventional truck and shovel (mining) methods BOE barrels of oil equivalent BOE/d barrels of oil equivalent per day C$ or $ Canadian dollars "Canadian Natural Resources Limited", "Canadian Natural", "Company", "Corporation"

Canadian Natural Resources Limited and includes, where applicable, reference to subsidiaries of and partnership interests held by Canadian Natural Resources Limited and its subsidiaries

CO2 carbon dioxide CO2e carbon dioxide equivalents crude oil includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal bitumen, mining bitumen and synthetic crude oil CSS Cyclic Steam Stimulation development well well drilled inside the established limits of an oil or gas reservoir or in close proximity

to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive

dry well well that proves to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion EOR Enhanced Oil Recovery exploratory well well that is not a development well, a service well, or a stratigraphic test well extension well well that is drilled to test if a known reservoir extends beyond what had previously been believed to be the outer reservoir perimeter fee title interest absolute ownership of legal title to mineral lands, subject to conditional interests that may have been granted from the title, such as petroleum and natural gas leases FPSO Floating Production, Storage and Offloading vessel GHG greenhouse gas gross acres total number of acres in which the Company has a working interest or fee title interest gross wells total number of wells in which the Company has a working interest Horizon Horizon Oil Sands IFRS Accounting Standards International Financial Reporting Standards as issued by the International Accounting

Standards Board

Mbbl thousand barrels MBOE thousand barrels of oil equivalent Mcf thousand cubic feet Mcf/d thousand cubic feet per day MD&A Management's Discussion and Analysis MMbbl million barrels MMBOE million barrels of oil equivalent MMBtu million British thermal units MMcf million cubic feet MMcf/d million cubic feet per day MM$ million Canadian dollars MOU Memorandum of Understanding between the Government of Canada and the Government of Alberta dated November 27, 2025 NGLs natural gas liquids net acres gross acres multiplied by the percentage working interest or fee title interest therein owned by the Company net wells gross wells multiplied by the percentage working interest therein owned by the Company NYSE New York Stock Exchange OPEC+ Organization of Petroleum Exporting Countries Plus Paris Agreement The Paris Agreement is an agreement within the United Nations Framework Convention on Climate Change, on climate change mitigation, adaption, and finance signed in 2016. productive well exploratory, development or extension well that is not dry proved property property or part of a property to which reserves have been specifically attributed PRT Petroleum Revenue Tax Quest Quest Carbon Capture and Storage ("CCS") project SAGD Steam-Assisted Gravity Drainage SCO synthetic crude oil, a mixture of liquid hydrocarbons derived by either partially or fully upgrading bitumen SEC United States Securities and Exchange Commission service well well drilled or completed for the purpose of supporting production in an existing field and drilled for the specific purposes of gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion stratigraphic test well drilling effort, geologically directed, to obtain information pertaining to a specific

geologic condition and ordinarily drilled without the intention of being completed for hydrocarbon production

TMX Trans Mountain Expansion pipeline TSX Toronto Stock Exchange UK United Kingdom unproved property property or part of a property to which no reserves have been specifically attributed US United States working interest interest held by the Company in a crude oil or natural gas property, which interest

normally bears its proportionate share of the costs of exploration, development, and operation as well as any royalties or other production burdens

Advisory SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements relating to Canadian Natural Resources Limited (the "Company" or "Canadian Natural") in this Annual Information Form ("AIF") or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, abandonment expenditures, income tax expenses, and other targets provided throughout this AIF constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to the Company's assets at Horizon, AOSP, the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby, Jackfish and Pike thermal oil sands projects, the operations of the North West Redwater bitumen upgrader and refinery, construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or NGLs that the Company may be reliant upon to transport its products to market, the decommissioning and abandonment of certain of the Company's assets and the timing thereof, the development and deployment of technology and technological innovations, the assumption of operations at processing facilities, the "2026 Activity" section of this AIF with respect to budgeted capital expenditures for 2026, targeted decommissioning activities in International and the timing thereof, the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term, the materiality of the impact of litigation and tax interpretations on the Company's results, any targeted payouts pursuant to the Company's free cash flow allocation policy, and the Company's acquisitions, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.

In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of OPEC+, the impact of conflicts in the Middle East, in Ukraine and in Venezuela, the restriction or disruption of global trade routes, the impact of changes to US economic policy, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for, and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; changes and uncertainty in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased or expanded); uncertainty in the regulatory framework governing GHG emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps, and the implementation of the MOU; political uncertainty, including changes in government, actions of or against terrorists, insurgent groups or other conflict including conflict between states; the Company's ability to prevent and recover from a cyberattack and other cyber-related crimes and incidents; industry capacity; the Company's ability to implement its business strategy, including exploration and development activities; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; the Company's ability to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for, and production and sale of, crude oil and natural gas and in mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels, the timing and success of integrating the business and operations of acquired companies and

assets, including the acquisition of the remaining 10% interest in the AOSP mines and other acquisitions that occurred in 2025; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; changes to future abandonment and decommissioning costs; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short-, medium- and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the impact of legal proceedings to which the Company is a party; the adequacy of the Company's provision for taxes; and other circumstances affecting revenues and expenses.

The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state, and local laws and regulations such as restrictions on production or emissions, the imposition of tariffs, export restrictions or embargoes on the Company's products (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased or expanded), changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations (including the implementation of the MOU). Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available. For additional information refer to the "Risk Factors" section of this AIF.

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this AIF could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this AIF, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.

SPECIAL NOTE REGARDING CURRENCY, FINANCIAL INFORMATION, PRODUCTION AND RESERVES

In this AIF, all references to dollars refer to Canadian dollars unless otherwise stated. Reserves and production data are presented on a "before royalties" or "company gross" basis and realized prices are net of blending and feedstock costs and exclude the effects of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent or BOE. A BOE is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.

The Company's audited consolidated financial statements and annual MD&A for the most recently completed fiscal year ended December 31, 2025, dated March 4, 2026, are herein incorporated by reference, and certain information included in this AIF, has been prepared in accordance with IFRS Accounting Standards. In the Company's annual MD&A for the year ended December 31, 2025, all references to synthetic crude oil in relation to the Oil Sands Mining and Upgrading segment, including realized pricing, production volumes, sales volumes, and netback calculations, are presented inclusive of mining bitumen. For details refer to the "Definitions and Abbreviations" section of the annual MD&A. Unless otherwise noted in this AIF, synthetic crude oil and mining bitumen are reported separately.

For the year ended December 31, 2025, the Company retained Independent Qualified Reserves Evaluators ("IQRE"), Sproule International Limited ("Sproule ERCE") and GLJ Ltd. ("GLJ"), to evaluate and review all of the Company's proved and proved plus probable reserves with an effective date of December 31, 2025 and a preparation date of February 9, 2026. Sproule ERCE evaluated and reviewed the North America and International light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal bitumen, natural gas and NGLs reserves. GLJ evaluated the Oil Sands Mining and Upgrading mining bitumen and SCO reserves. The evaluations and reviews were conducted and prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and disclosed in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") requirements.

The Company annually discloses net proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current costs in accordance with United States Financial Accounting Standards Board Topic 932 "Extractive Activities - Oil and Gas" in the Company's annual report on Form 40-F filed with the SEC and in the "Supplementary Oil and Gas Information" section of the Company's 2025 Annual Report, which is incorporated herein by reference.

SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES

This AIF includes references to non-GAAP and other financial measures as defined by National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). These financial measures, including "adjusted net earnings from operations", "adjusted funds flow", "netback", "realized price", "net capital expenditures", "long-term debt, net" and "free cash flow", are used by the Company to evaluate its financial performance, financial position and cash flow. These financial measures are not defined by IFRS Accounting Standards and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the Company's financial statements, as applicable, as an indication of the Company's performance. Descriptions of and reconciliations to the most directly comparable financial measure for "adjusted net earnings from operations", "adjusted funds flow", "netback", "realized price", "net capital expenditures" and "long-term debt, net", are provided in the "Non-GAAP and Other Financial Measures" section of the Company's annual MD&A for the year ended December 31, 2025, dated March 4, 2026, and are incorporated by reference herein. "Free cash flow" is a non-GAAP financial measure. The Company considers free cash flow a key measure in demonstrating the Company's ability to generate cash flow to fund future growth through capital investment, to repay debt and to pay returns to shareholders through dividends and share repurchases pursuant to its free cash flow allocation policy. Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and abandonment expenditures.

SPECIAL NOTE REGARDING COMMON SHARE SPLIT AND COMPARATIVE FIGURES

At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024, shareholders of record received one additional share for every one common share held, with common shares trading on a split-adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods prior to the two for one common share split have been updated to reflect the common share split.

SPECIAL NOTE REGARDING AMENDMENTS TO THE COMPETITION ACT (CANADA)

On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement, which impacted environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. These amendments include substantial financial penalties and, effective June 20, 2025, a private right of action which will permit private parties to seek an order from the Competition Tribunal under the deceptive marketing practices provisions. Subsequently, on November 4, 2025, the federal government tabled the 2025 Budget, which proposed further amendments to the Competition Act, namely removing the requirement that businesses substantiate their environmental representations about a business or business activity based on an internationally recognized methodology, and eliminating private rights of action under the revised business-activity greenwashing provision. Uncertainty surrounding the interpretation and enforcement of this legislation, which includes the status of any proposed or future amendments, may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results.

Corporate Structure

Canadian Natural Resources Limited was incorporated under the laws of the Province of British Columbia on November 7, 1973 as AEX Minerals Corporation (N.P.L.) and, on December 5, 1975, changed its name to Canadian Natural Resources Limited. Canadian Natural was continued under the Companies Act (Alberta) on January 6, 1982 and was further continued under the Business Corporations Act (Alberta) on November 6, 1985. Since that time, the Company has completed a number of transactions which have resulted in amalgamations, arrangements and amendments to constating documents, none of which have resulted in material changes thereto.

At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving an amendment to the Company's Articles of Amalgamation to subdivide the issued and outstanding common shares on a two-for-one basis. Articles of Amendment were subsequently filed on May 22, 2024. (Further details are disclosed under "Description of Capital Structure - Common Shares" in this AIF.)

In the last ten years, the Company has amalgamated pursuant to the Business Corporations Act (Alberta) under the name Canadian Natural Resources Limited with the following:

Amalgamated Company: Date

EOG Resources Canada Inc. January 1, 2015

Laricina Energy Ltd. January 1, 2019

CNRL Upgrading Limited October 1, 2020

Painted Pony Energy Ltd. January 1, 2021

Storm Resources Ltd.; Storm Gas Resource Corp.; CNR Montney Ltd. January 1, 2022

Horizon Construction Management Ltd. January 1, 2023

The Company's current head and registered office is located in Calgary, Alberta, Canada at 2100, 855 - 2nd Street S.W., T2P 4J8. In June 2026, the Company is relocating its head and registered office to 400 - 4th Avenue S.W., Calgary, AB, T2P 0J4.

The main operating subsidiaries and partnerships of the Company, percentage of voting securities owned either directly or indirectly, and their jurisdictions of incorporation are as follows:

Jurisdiction of Incorporation % Ownership Subsidiary:

Canadian Natural Upgrading Limited	Alberta	100
CanNat Energy Inc.	Delaware	100
CanNat Liquids Marketing Limited	Alberta	100
CNR International (U.K.) Developments Limited	England	100
CNR International (U.K.) Limited	England	100
CNR International (Côte d'Ivoire) SARL	Côte d'Ivoire	100
CNR International (South Africa) Limited	Alberta	100
CNR (Redwater) Limited	Alberta	100
Sukunka Natural Resources Inc.	Alberta	100
CNR Petro Resources Limited	Alberta	100

Partnership:

CNR Montney Partnership Alberta 100

Canadian Natural, as the managing partner, and CNR Petro Resources Limited, are partners of CNR Montney Partnership, a general partnership.

In the ordinary course of business, Canadian Natural restructures its subsidiaries and partnerships to maintain efficient operations.

The audited consolidated financial statements of Canadian Natural include the accounts of the Company and all of its subsidiaries and wholly-owned partnerships as well as certain of the Company's activities which are conducted through joint arrangements.

General Development of the Business 2023

The Company approved the final investment decision to proceed with the Pike 1 thermal in situ project as part of its 2023 capital budget. Drilling and pipeline development in support of the Pike 1 project commenced in late 2024 with the Company drilling two SAGD pads in 2025, which are tied into the existing Jackfish facilities. The first of the two pads began production in late 2025 with the second targeted to come on production in the second quarter of 2026 and are expected to keep the Jackfish plants at full capacity. In December 2023, the Company approved the decision to proceed with the Naphtha Recovery Unit Tailings Treatment project at Horizon, for a total capital investment of approximately $357 million. The project commenced in 2024 and is expected to be mechanically complete in the third quarter of 2027.

The Company made a number of adjustments to its debt financing plan in 2023. In June 2023, the Company extended its

$2,425 million revolving syndicated credit facility by three years to mature in June 2027. In July 2023, the Company filed base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$3,000 million of debt securities in the United States, both of which expired in August 2025, replacing the Company's previously filed base shelf prospectuses that would have expired in August 2023. In September 2023, the Company extended its $500 million revolving credit facility to mature in February 2025. In November 2023, the Company also repaid $405 million of 1.45% medium-term notes.

In November 2023, the Company announced a number of senior management promotions positioning the Company to continue the strategic development of its long life, low decline assets and low capital exposure assets and the creation of value for shareholders into the future.

2024

At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a special resolution approving a two for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024, shareholders of record received one additional share for every one common share held, with common shares trading on a split-adjusted basis beginning June 11, 2024.

During 2024, the Company increased its contracted crude oil transportation capacity to 256,500 bbl/d, expanding its committed capacity to Canada's West Coast and to the United States Gulf Coast ("USGC"). After the TMX was successfully commissioned in the second quarter of 2024, the Company increased its capacity on the TMX by 75,000 bbl/d to a total of 169,000 bbl/d. The Company also increased its capacity on the Flanagan South pipeline in 2024 by an additional 55,000 bbl/d for a total of 77,500 bbl/d, further expanding the Company's heavy oil diversification and market access to the USGC. The Company also has committed capacity of 10,000 bbl/d on the Keystone Base pipeline, with direct access to the USGC.

In December 2024, the Company completed acquisitions of Chevron Canada Limited's ("Chevron") Alberta assets, which included Chevron's 20% interest in AOSP and a 70% operated interest in light crude oil and liquids-rich Duvernay assets. As a result of these acquisitions, the Company owned 90% of AOSP, which included the Muskeg River and Jackpine mines, the Scotford Upgrader and Quest. The acquisitions also included various working interests in a number of other non-producing oil sands leases. The aggregate consideration for these assets was US$6.5 billion, subject to closing adjustments.

The Company also made a number of adjustments to its debt financing plan in 2024. The Company extended the maturity of its

$2,425 million revolving syndicated credit facility from June 2025 to June 2028 and extended its $500 million revolving credit facility from February 2025 to February 2026. The Company repaid $320 million of 3.55% medium-term notes and US$500 million of 3.80% of US dollar debt securities. In connection with the acquisition of Chevron's Alberta assets, the Company entered into a $4,000 million non-revolving term credit facility maturing December 2027. In December, the Company also issued $500 million of 4.15% medium-term notes due December 2031 at $99.836 per note, US$750 million of 5.00% notes due December 2029 at US$99.968 per note and US$750 million of 5.40% notes due December 2034 at US$99.837 per note.

In 2024, the Company continued to renew its senior management team with additional promotions positioning the Company to continue its strategic program for the creation of value for shareholders into the future.

2025

During 2025, the Company closed an acquisition of lands and production in the Palliser Block located in southern Alberta, which added production volumes of approximately 50,000 BOE/d, including 20,000 bbl/d of Mannville light crude oil and NGLs. This acquisition also included approximately 1.1 million net acres of land, with identified light crude oil inventory for approximately 850 locations. The Company also closed an acquisition of liquids-rich Montney assets located in the Grande Prairie area of northern Alberta with production from the acquisition of approximately 32,000 BOE/d, including 12,500 bbl/d of NGLs. Finally, the Company completed the AOSP asset swap with Shell Canada Limited and affiliates ("Shell"). As a result of the transaction, the Company acquired the remaining 10% interest in the AOSP mines, associated reserves, and additional working interests in a number of other non-producing oil sands leases in exchange for a 10% working interest in the non-operated Scotford Upgrader and Quest. The Company now owns and operates 100% of the AOSP mines, and retains a non-operated 80% working interest in the Scotford Upgrader and Quest.

During 2025, the Company entered into a long-term natural gas supply agreement to supply 140,000 MMBtu/d of natural gas for a term of 15 years, with delivery anticipated to begin in 2030 as all conditions precedent have been waived by the counterparty. Under the terms of the agreement, the Company will deliver natural gas to its counterparty in Illinois, USA and receive a Japan-Korea Marker index price less deductions for transportation and liquefaction.

The Company also made a number of adjustments to its debt financing plan in 2025. The Company extended its $500 million revolving credit facility from February 2026 to June 2027. The Company increased its $2,425 million revolving syndicated facility to $2,565 million, and extended $2,425 million originally due June 2027 to June 2029. The remaining $140 million outstanding under this facility will mature in June 2027. The Company repaid US$600 million of 3.90% US dollar debt securities and US$600 million of 2.05% US dollar debt securities. In August 2025, the Company filed base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$4,500 million of debt securities in the United States, both of which expire in September 2027, replacing the Company's previously filed base shelf prospectuses that would have expired in August 2025. In October 2025, the Company completed the exchange of US$747 million of the outstanding restricted 5.00% US dollar debt securities due December 2029 and US$750 million of the outstanding restricted 5.40% US dollar debt securities due December 2034. The exchanged notes were not subject to transfer restrictions and did not impact the Company's level of indebtedness. In December 2025, the Company issued $550 million of 3.30% medium-term notes due December 2028 at $99.887 per note, $550 million of 3.75% medium-term notes due February 2031 at $99.781 per note and $550 million of 4.55% medium-term notes due February 2036 at $99.700 per note.

In 2025, the Company continued to renew its senior management team with additional promotions positioning the Company to continue its strategic program for the creation of value for shareholders into the future.

Description of the Business

Canadian Natural is a Canadian based senior independent energy company engaged in the acquisition, exploration, development, production, marketing and sale of crude oil, natural gas and NGLs. The Company's principal core regions of operations are western Canada, the UK sector of the North Sea and Offshore Africa.

The Company operates and maintains a large working interest in a majority of the prospects in which it participates. The Company's objectives are to increase crude oil and natural gas production, reserves, cash flow and net asset value on a per common share basis through the economic and sustainable development of its existing crude oil and natural gas properties and through the discovery and/or acquisition of new reserves. The Company strives to meet these objectives and its commitments to environmental stewardship and safety excellence.

The Company has a full complement of management, technical and support staff to pursue December 31, 2025, the Company had the following full time equivalent permanent employees:	these	objectives. As of
North America, Exploration and Production		3,068
North America, Oil Sands Mining and Upgrading		4,970
North Sea and Offshore Africa		302
Corporate		2,410
Total Company		10,750

Operational discipline, together with safe, effective and efficient operations and cost control, are fundamental to the Company. By consistently managing costs throughout all industry cycles, the Company believes it will achieve continued growth. The Company achieves safe operations that are effective and efficient and controls cost by developing area knowledge and by maintaining high working interests and operator status in its properties. The Company has grown through a combination of internal growth and strategic acquisitions. Acquisitions are made with a view to either entering new core regions or increasing the Company's presence in existing core regions.

The Company's business approach is to maintain large project inventories and production diversification among each of its products: SCO, mining bitumen, natural gas, light and medium crude oil and NGLs, thermal bitumen, primary heavy crude oil and Pelican Lake heavy crude oil. The Company's large diversified project portfolio enables the effective allocation of capital to higher return opportunities, which together provide complementary infrastructure and balance throughout the business cycle. SCO from the oil sands mining and upgrading operations in northern Alberta accounted for 36% of 2025 annual production(1). Natural gas, primarily produced in Alberta, British Columbia and Saskatchewan, accounted for 27% of 2025 annual production. Light and medium crude oil and NGLs represented 11% of 2025 annual production, and were produced from Alberta, British Columbia, Saskatchewan and Manitoba, as well as from the Company's North Sea and Offshore Africa operations. Thermal bitumen, which accounted for 17% of 2025 annual production, primary heavy crude oil, which accounted for 6% of 2025 annual production, and Pelican Lake heavy crude oil, which accounted for 3% of 2025 annual production, were also produced from Alberta and Saskatchewan. The Company's Midstream assets, primarily comprised of two operated pipeline systems (ECHO and Pelican Lake), and a 50% working interest in an 84 megawatt cogeneration plant at Primrose, provide cost effective infrastructure supporting the Company's heavy crude oil and thermal bitumen operations. Midstream assets also include a 50% equity interest in the North West Redwater Partnership.

The Company's Canadian crude oil production is marketed to purchasers located in Canada and other international destinations. Purchasers that take delivery in Canada may subsequently export those products to other international destinations using their own transportation. The Company has contracted pipeline capacity for approximately 22% of its liquids production. This includes contracted capacity on the Flanagan South pipeline (77,500 bbl/d) and the Keystone Base pipeline (10,000 bbl/d). The Company also has contracted capacity on TMX (169,000 bbl/d) which gives the Company the option to sell either to customers in Western Canada or to international markets. The Company also markets natural gas directly to purchasers in both Canada and other international markets. Purchasers that take delivery in Canada may subsequently export those products to other international destinations using their own transportation. Natural gas is distributed to customers in Canada via the TC Canadian Mainline and other pipelines such as the Enbridge Westcoast system. NGLs are marketed to purchasers located in Canada, some of whom may export those products to other international destinations. The Company's offshore production from its North Sea and West African operations is sold primarily into European markets.

(1) Annual production calculated on a BOE basis. For the purposes of this calculation, SCO includes mining bitumen.

1. ENVIRONMENTAL MATTERS Environmental Management Approach

   The Company has a Corporate Statement on Environmental Management which affirms that environmental stewardship is a fundamental value of the Company. This commitment ensures the Company, as well as its employees and contractors, carry out all business activities in compliance with applicable regional, national and international regulations and industry standards. The Company's oil sands mining and the UK divisions also conduct operations in accordance with Environmental Management Systems that are audited by independent third parties. As part of the Company's corporate governance mandate, the Company's environmental specialists track performance to numerous environmental performance indicators in its domestic and international operations, and regularly report to the senior management of the Company, which in turn reports on environmental matters directly to the Health, Safety, Asset Integrity and Environmental Committee of the Board of Directors. This Committee's mandate also includes oversight of the Company's policies and programs related to climate change and GHG emissions, social/community matters and stakeholder relations.

   The Company regularly engages with and submits to inspections by the various government regulatory authorities in each of the regions where the Company operates. The Company's environmental risk management strategy includes working constructively with legislators and regulators to ensure that any new or revised legislation, regulations or policies properly reflect a balanced approach to sustainable development. The Company has processes in place and is committed to complying with all existing environmental standards and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet current environmental protection requirements. In Canada, these requirements apply to all operators in the crude oil and natural gas industry and it is not anticipated that the Company's competitive position within the industry will be adversely affected by changes in applicable legislation; however, there are no assurances that future environmental laws and regulations will not have a material effect on the Company's business, financial condition and results of operations.

   The Company has internal procedures designed to ensure that the environmental aspects of new acquisitions and developments are taken into account prior to proceeding. The Company's Environmental Management Plan (the "Plan") along with the Company's operating guidelines and strategies are intended to reduce the environmental impact of operations while meeting: regulatory requirements; regional management frameworks for air quality and emissions, ground and surface water, and biodiversity; industry operating standards and guidelines; and internal corporate standards. Adequate and proper training of, and diligent execution by, the Company's operators and contractors is key to the effectiveness of the Company's environmental management programs and supports efforts to reduce the Company's environmental footprint.

   Canada

   The Company continues to invest in people, facilities and infrastructure, as well as new and proven technologies, to recover and process crude oil and natural gas resources efficiently and in an environmentally responsible manner. As a part of the Plan, the Company has implemented a number of programs intended to reduce its environmental footprint including: various programs designed to reduce GHG and methane emissions; assessment of impacts of the Company's operations, together with implementation of avoidance and mitigation programs that seek to maintain biodiversity for terrestrial and aquatic systems and high value ecosystems; the continued review and evaluation of new technologies designed to reduce environmental impacts from operations; and optimization programs that seek to improve efficiencies at the Company's facilities.

   The Company, through industry associations, is working with Canadian legislators and regulators as they develop and implement laws and regulations to properly reflect a balanced approach to sustainable development, such as programs to support industry investments in environmental performance improvement and emissions reduction.

   Bill C-59, which received royal assent in June 2024, created among other things, a new investment tax credit ("ITC") to support investment in eligible carbon capture, utilization and storage ("CCUS") projects by providing a refundable ITC of up to 50% on carbon capture equipment and 37.5% on qualified carbon transportation, storage or usage equipment from 2022 to 2030, with these ITC rates being halved from 2031 to 2040 and fully phased out after 2040. In the 2025 Budget released on November 4, 2025, the federal government announced its intention to extend the availability of the CCUS ITCs by five years so that the full rates will apply to eligible expenditures from 2022 to 2035. The Government of Alberta also established the Alberta Carbon Capture Incentive Program in 2023, which provides a 12% grant on eligible capital costs for CCUS projects.

   Air quality programs are an essential part of the Company's environmental work plan and are operated within all industry and regulatory standards and guidelines. The Company also participates in air quality monitoring through regional organizations. Data collected through these regional air shed monitoring programs is used by government agencies to develop regional management programs and frameworks.

   The Company has a well-established venting and solution gas conservation program at its facilities and incorporates future conservation opportunities into new projects and facilities. As part of the Company's initiatives to optimize and improve fuel gas efficiency, the Company also monitors compressor fleet performance and has ongoing methane reduction programs for pneumatic devices.

   As part of the Company's water management strategy, the Company has water management programs designed to improve recycle rates and reduce freshwater use. These programs include the Hydraulic Fracturing Operating Practices developed by the Canadian Association of Petroleum Producers, which are intended to support a responsible approach to hydraulic fracturing and water management.

   The Company has implemented programs for well abandonment and decommissioning that allow for the progressive reclamation of large contiguous areas of land. In 2025, the Company's environmental liability reduction program completed the decommissioning of 2,753 inactive wells and has 12,620 sites progressing towards reclamation certification. In addition, for 2025, the Company received 1,205 reclamation certificates representing 2,188 hectares of land. Since 2021, the Company has decommissioned 12,969 inactive wells and received 5,393 reclamation certificates representing 10,556 hectares of reclaimed land. The Company also conducted additional decommissioning and clean up activities at various active and inactive facilities to address environmental liabilities at its operating sites.

   In addition, the Company has comprehensive programs in place for: (i) tailings management in its oil sands mining operations to minimize fine tailings and support reclamation; (ii) monitoring programs to assess changes to biodiversity, wildlife and fisheries, in order to manage construction and operational effects and to assess reclamation success; (iii) groundwater monitoring for all thermal in situ and mine operations; (iv) an active spill prevention and management program; and (v) an internal environmental management system for conformance audit and inspection of operating facilities. The Company also participates in the Oil Sands Monitoring Program, a joint program sponsored by the federal government and the Government of Alberta, which supports the regional monitoring of air, surface water, groundwater, wetlands and biodiversity.

   International

   In 2025, the Company continued decommissioning activities in the North Sea, including cessation of production at the Ninian South platform and the associated subsea fields. Stakeholder engagement was completed ahead of formally submitting the Ninian South Decommissioning Program for regulatory approval in December 2025. Decommissioning activities will continue at the Ninian Hub throughout 2026. Additionally, based on current and forecasted economic conditions, including commodity prices and market egress, the Company determined that the T-Block assets were no longer economically viable. Cessation of production has been accelerated to the first quarter of 2027 and associated crude oil reserves were de-booked.

2. REGULATORY MATTERS

   The Company's business is subject to regulations and rules developed by legislation and governmental agencies. Certain key regulatory regimes impacting the Company's operations are summarized in the following paragraphs.

   Canada

   Petroleum and Natural Gas Leases

   The crude oil and natural gas industry in Canada operates under legislation and regulations that govern exploration, development, production, refining, marketing, transportation, prevention of waste and other activities.

   The Company's Canadian properties are primarily located in Alberta, British Columbia, Saskatchewan, and Manitoba. Most of these properties are held under leases/licences obtained from the applicable federal or provincial governments, which give the holder the right to explore for and produce bitumen, crude oil, natural gas and NGLs. The remainder of the properties are held under freehold (private ownership) leases.

   Conventional petroleum and natural gas leases issued by the provinces of Alberta, Saskatchewan and Manitoba have a primary term from two to five years, and British Columbia leases/licences presently have a primary term of up to ten years. Those leases that are producing or are capable of producing at the end of the primary term will "continue" for the productive life of the lease.

   An Alberta oil sands primary lease is issued for fifteen years. Primary oil sands leases that are designated as "producing" will continue for as long as the minimum level of production is maintained while those designated as "non-producing" and not meeting the required minimum level of production can be continued by payment of escalating rentals.

   The provincial governments regulate the production of crude oil, natural gas and NGLs. Government royalties are payable on crude oil, natural gas and NGLs produced from leases owned by the province. The royalties are determined by regulation and are generally calculated as a percentage of production adjusted by a number of different factors including selling prices, production levels, recovery methods, transportation and processing costs, location and date of discovery.

   Royalties

   Alberta royalties on oil sands projects are based on a sliding scale ranging from 1% to 9% on a gross revenue basis pre-payout and 25% to 40% on a net revenue basis post-payout, depending on benchmark crude oil pricing.

   Effective January 1, 2017, the Alberta government adopted the Modernized Royalty Framework ("MRF") for conventional crude oil, natural gas and NGLs royalties. As a result, Alberta currently has a parallel royalty regime system with the previous Alberta Royalty Framework ("ARF") continuing to apply until December 31, 2026 to wells drilled prior to July 13, 2016 and the MRF applying to wells drilled on or after January 1, 2017. For wells drilled between July 13, 2016 and December 31, 2016 producers may opt in to the MRF if certain criteria are met. Under the MRF, conventional royalty rates range from 5% to 36% for natural gas and NGLs and 5% to 40% for crude oil.

   On May 19, 2022, the Government of British Columbia announced a new royalty framework, which will come into effect on January 1, 2027. The new framework will replace previous drilling incentive programs with a revenue minus costs model similar to other Canadian jurisdictions. New wells will pay a flat royalty rate of 5% until the capital spent on drilling and completions is recovered and then a price sensitive royalty rate between 5% and 40% will apply and vary based on commodity type. Details of

   certain cost allowances and reference prices remain to be finalized by the BC government through consultation with stakeholders.

   Taxation

   The Company was subject to federal and provincial income taxes in Canada at a combined rate of approximately 23.14% in 2025. The Company is also subject to federal legislation implementing a 2% tax on repurchases of equity in 2025. The 2% tax is applicable to repurchases and issuances of equity that occur after December 31, 2023.

   Abandonment and Reclamation - Liability Management

   The Alberta Energy Regulator ("AER") established a Liability Management Framework (the "Framework") as part of its life-cycle management of oil and natural gas wells, facilities and pipelines, which imposes mandatory annual minimum spend requirements on licensees for the closure of inactive wells and related infrastructure. Under the Framework, the AER assigns a licensee an annual minimum spend requirement for reclamation and abandonment activities to be completed based on a licensee's proportionate share of the provincial inventory of inactive wells and related infrastructure, among other factors. In Alberta, the mandatory minimum spend requirements are reviewed annually and have increased from 4% in 2022 to the current rate of 6.2% in 2025. The Government of Saskatchewan has a similar program in place (the Inactive Liability Reduction Program), which had a 6% minimum spend requirement in 2025. In British Columbia, the Dormancy and Shutdown Regulations also set out mandatory targets for the decommissioning and restoration of inactive wells and facilities. In addition to minimum spend requirements for abandonment and reclamation, each of the provincial regulators has the ability to require licensees to post financial security to secure a licensee's abandonment and reclamation obligations.

   Carbon / GHG

   Governments in jurisdictions where the Company operates have developed GHG regulations as part of their provincial, federal and international climate change commitments. The Company continuously monitors developments in the GHG regulatory environment in applicable jurisdictions to assess the cost impact of new and existing regulations on current and future operations and proposed projects under consideration.

   • Federal Carbon Policy and GHG Emissions Regulation

     The federal government ratified the Paris Agreement, which included a commitment to reduce Canada's GHG emissions by 40-45% from 2005 levels by 2030. In December 2024, the federal government updated its commitment to extend the timing to achieve the national GHG emission reduction target to 2035. The federal regulations supporting the Paris Agreement mandate that the federal carbon price increase in annual increments of $15/tonne after 2022 to $170/tonne by 2030. The federal Clean Fuel Regulations ("CFR"), which took effect on July 1, 2023, require reductions in the carbon intensity of gasoline and diesel fuels produced or sold in Canada. The federal Clean Electricity Regulations ("CER") came into effect on January 1, 2025, and establishes GHG emission limits for almost all fossil fuel-powered electricity generation units, beginning in 2035.

     In addition to existing federal GHG regulations and the CFR, the federal government published draft regulations in 2024 that propose to cap emissions from the oil and gas sector through a national cap-and-trade system. This has not yet been implemented and is dependent on final agreements negotiated as part of the MOU (see below for further discussion). In 2025, new federal regulations were also released that are intended to control the release of volatile organic compounds (VOCs) from petroleum refineries and upgraders; truck, rail, marine, and pipeline terminals; petrochemical facilities; bulk fuel facilities; and steel mills.

     In November 2025, the federal and Alberta governments entered into the MOU which is intended to increase western Canada's energy production and establish Canada as an energy leader while reducing GHG emissions through innovative technologies and infrastructure programs. The MOU included the following:

     • The federal government agreed not to implement an oil and gas emissions cap, contingent on the province of Alberta meeting certain commitments, one of which is related to the development of carbon capture infrastructure;

     • The application of the CER in Alberta was suspended pending the finalization of a new carbon pricing agreement to be administered through Alberta's Technology Innovation and Emissions Reduction Regulation ("TIER") program, the details of which are to be negotiated and agreed upon by the parties on or before April 1, 2026; and

     • A commitment by the two governments to work collaboratively to design and implement a globally competitive, longterm carbon pricing scheme, carbon levy recycling protocols, and sector-specific stringency factors for large emitters in both the oil and gas and electricity sectors through Alberta's TIER system. Under this proposal, the TIER system will ramp up to a minimum effective credit price of $130/tonne. The two governments are anticipated to conclude an agreement on industrial carbon pricing on or before April 1, 2026 in furtherance of this agreement.

   Although the MOU appears supportive of Canada's energy sector, there are no assurances that the parties will reach final agreement on all of the necessary elements required to enable the MOU framework or the environmental laws and regulations negotiated as part of the MOU to have a favourable impact on the oil and natural gas industry in Alberta or the Company, or, if not adopted with the necessary elements, may ultimately have an adverse effect on the Company's business, financial condition and operations.

   • Provincial GHG Policy and Regulation

     Industrial carbon pricing regulatory systems in all provinces are subject to periodic review by the federal government to assess the adequacy of the provincial systems against the federal Greenhouse Gas Pollution Pricing Act. To the extent a province's carbon pricing system does not meet the federal stringency requirements, the federal backstop regulations apply.

     Alberta: In Alberta, TIER sets the carbon pricing framework that applies to the Company's facilities with emissions greater than 100,000 tonnes CO2e/year, and certain facilities opted into the TIER system by the Company. In 2025, the carbon price in Alberta for emissions above the TIER regulated limits was $95/tonne. In May 2025, the Alberta government indefinitely capped the carbon price at $95/tonne, which may be subject to change following finalization of a new carbon pricing agreement with the federal government on or before April 1, 2026 (as stipulated in the MOU). Emissions from the non-operated Scotford Upgrader and North West Redwater bitumen upgrader and refinery are also subject to TIER.

     British Columbia: In 2025, the industrial carbon price in British Columbia under the province's output-based price system was $95/tonne and will increase by $15/tonne CO2e annually until it reaches $170/tonne of CO2e in 2030, in alignment with the federal carbon pricing schedule. In 2023, British Columbia announced its intention to implement a Net-Zero New Industry policy as well as an emissions cap for the oil and gas industry. This cap is intended to ensure that the province meets its emissions reduction target of 33-38% below 2007 emission levels by 2030. In 2024, British Columbia announced that it would be introducing regulatory measures to backstop the federal carbon emissions cap, which were to apply in the event of gaps between federal and provincial targets, and in the event that the federal emissions cap is not implemented or cancelled.

     Saskatchewan: As part of its Prairie Resilience Plan, in 2018 the Saskatchewan government enacted the Management and Reduction of Greenhouse Gases (Standards and Compliance) Regulations, that apply to facilities emitting more than 25 kilotonnes of CO2e annually. This regulation required the Company's North Tangleflags in situ heavy crude oil facility and the Senlac in situ heavy crude oil facility to meet reduction targets for GHG emissions commencing in 2020. This regulation also enables facilities that emit less than 25 kilotonnes of CO2e annually to aggregate and opt-in to the Saskatchewan regulatory system as an alternative to the federal fuel charge. In April 2025, the province of Saskatchewan paused the application and collection of industrial carbon taxes. Since this would result in Saskatchewan not meeting the federal stringency requirement, the province may be subject to the federal backstop regulation if applied by the federal government in the future.

     Manitoba: In the absence of provincial regulations for carbon pricing and GHG emissions, the federal output-based pricing system and carbon pricing schedule applies to Manitoba facilities with emissions greater than or equal to 50 kilotonnes CO2e annually. Facilities with emissions equal to or greater than 10 kilotonnes CO2e annually can voluntarily opt-in to the system.

   • Methane Emissions Reduction Regulations

   The federal government's methane regulation which came into effect on January 1, 2020, applies nationally unless provinces reach equivalency agreements with the federal government. The federal government originally had a commitment to reduce methane emissions from the oil and gas sector by 40-45% from the 2012 levels by 2025. In 2021, the federal government set a target to further reduce methane emissions to achieve at least a 75% reduction below 2012 levels by 2030.

   The provinces of British Columbia, Alberta and Saskatchewan have equivalency agreements in place with the federal government that allow the applicable provincial methane regulations to govern in these three western provinces. The federal methane regulation continues to apply in the province of Manitoba.

   Pursuant to the MOU, the federal and Alberta governments intend to enter into a new methane equivalency agreement on or before April 1, 2026. Once concluded, this new equivalency agreement will extend the target date to achieve the mandated 75% methane emissions reduction (relative to 2014 levels) to 2035. In December 2025, the final methane regulation was enacted by the federal government, with phase-in of the regulatory requirements beginning January 1, 2028.

   United Kingdom

   Under existing law, the UK government has broad authority to regulate the petroleum industry, including exploration, development, conservation and rates of production.

   Taxation

   Effective January 1, 2016, the Petroleum Revenue Tax ("PRT") rate, which is a charge on certain crude oil and natural gas profits, was reduced to 0%. Allowable abandonment expenditures eligible for carryback to 2015 and prior taxation years for PRT purposes remain recoverable at 50%. In addition, the supplementary charge on oil and gas profits was reduced to 10%, also effective in 2016. An Investment Allowance on qualifying capital expenditures is deductible for supplementary charge purposes, subject to certain restrictions. For Corporation Tax and Supplementary Charge, allowable losses are eligible for carryback to prior taxation years. The UK government introduced an Energy Profits Levy ("EPL") in May 2022 at a rate of 25%. This was subsequently increased to 35% in November 2022. From November 1, 2024, the EPL was further increased to 38% and the investment allowance on qualifying capital expenditure of 29% was abolished. As a result of these changes, the tax rate applicable to taxable income from oil and gas activities is 78% subject to deduction of available investment allowance.

   In 2013, the UK government introduced a Decommissioning Relief Deed ("DRD"), which is a regulatory and contractual mechanism whereby the UK government guarantees its participation in future field abandonments through a recovery of PRT and corporate income tax.

   Carbon / GHG

   GHG emissions from the Company's UK operations are regulated under the UK Emissions Trading Scheme ("ETS"), which was launched on January 1, 2021 and replaced the UK's participation in a comparable European Union ("EU") system. The UK scheme is aligned with the EU ETS rules and applies to energy intensive industries, the power generation sector and aviation.

   Offshore Africa

   The terms of licences, including royalties and taxes payable on production or profit sharing arrangements, as appropriate, vary by country and, in some cases, by concession within each country.

   Development of the Espoir Field in Block CI-26 and the Baobab Field in Block CI-40, Offshore Côte d'Ivoire ("CDI"), are subject to Production Sharing Contracts ("PSC") which deem that tax or royalty payments to the government are satisfied by the government's share of profit oil. The current corporate income tax rate in CDI is 25% which is applicable to non-PSC income.

   In 2019, the CDI government communicated its intent to require the oil and gas sector operating in its jurisdiction to comply with the West African Economic and Monetary Union currency control regulations. The Company continues its discussions with the applicable authorities on a mechanism that will satisfy these regulations while, at the same time, allow for the expatriation of foreign currency not required for use by the Company in country.

   On January 24, 2025, the amendments to CDI's local content regulations took effect, which increased the requirement to use local personnel, businesses and services in Company operations. The Company has worked with its contractors and applicable authorities with regard to compliance with these regulations.

3. COMPETITIVE FACTORS

   The energy industry is highly competitive in all aspects of the business including the exploration for and the development of new sources of supply, the construction and operation of crude oil and natural gas pipelines and related facilities, the acquisition of crude oil and natural gas interests, the transportation and marketing of crude oil, natural gas, NGLs and surplus electricity generated at Company facilities, and the attraction and retention of skilled personnel. The Company's competitors include both integrated and non-integrated crude oil and natural gas companies as well as other petroleum products and energy sources.

4. RISK FACTORS

Given the dynamic nature of risk, the Company uses a multidisciplinary Enterprise Risk Management ("ERM") framework to identify, assess, and develop mitigation plans for risks that may affect the Company and its operations. The ERM framework incorporates a matrix approach to risk assessment that categorizes and aligns risks across operational areas, allowing teams to better understand the identified risks, their impacts on the Company's operations and the mitigation being undertaken to address these risks. This allows management to monitor potential risk exposures and the steps taken to address the identified risks or otherwise mitigate these exposures by identifying those individuals on the Company's Management Committee responsible for each of the identified risks. Reporting on the risks and related mitigating activity throughout the Company is also part of the ERM framework.

Volatility of Crude Oil and Natural Gas Prices

The Company's financial condition is substantially dependent on, and highly sensitive to, the prevailing price for crude oil and natural gas. Significant declines in crude oil or natural gas prices could have a material adverse effect on the Company's operations and financial condition and the value and amount of its reserves. This could include: a delay or cancellation of existing or future drilling, development, construction or expansion programs; curtailment in production at some properties; or result in unutilized long-term transportation commitments, all of which could have a material adverse effect on the Company's financial condition.

Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond the Company's control including instability in the international trade environment as a result of actual or threatened trade action by Canada and the US, or other key trade partners, including the imposition or threatened imposition of tariffs and retaliatory trade measures. Crude oil prices are primarily determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC+, the economic condition of Canada, the US, the European Union and Asia, government regulation, political stability in the Middle East and elsewhere, geopolitical conflicts (e.g. conflicts in the Middle East, in Ukraine and in Venezuela), the foreign supply of crude oil, the restriction or disruption of global trade routes, the price of foreign imports, the ability to secure adequate transportation for products which could be affected by pipeline constraints, the construction by third parties of new or expansion of existing pipeline capacity, government mandated curtailment, the availability of alternate fuel sources, weather conditions, and other factors. Natural gas prices realized by the Company are affected primarily in North America by supply and demand, weather conditions, industrial demand and the ability to secure adequate transportation for products, which could also be affected by pipeline constraints, government mandated curtailment, prices of alternate sources of energy, and government regulation. Crude oil and natural gas producers in Canada may receive discounted prices for their production relative to international prices due in part to constraints on the ability to transport and sell products to international markets. An ongoing failure to resolve such

constraints may extend the duration of discounted or reduced commodity prices realized by crude oil and natural gas producers, including the Company.

Any substantial or extended decline in prices of crude oil or natural gas could result in a delay or cancellation of existing or future drilling, development, construction or expansion programs, including, without limitation, at Horizon, AOSP, Primrose, Pelican Lake, Kirby, Jackfish, Pike, and international projects, or curtailment in production at some properties, or result in unutilized long term transportation commitments, all of which could have a material adverse effect on the Company's financial condition.

Approximately 27% of the Company's 2025 production on a BOE basis was primary heavy crude oil, Pelican Lake heavy crude oil and bitumen. The market prices for these products differs from the established market indices for light and medium grades of crude oil due principally to quality differences. As a result, the price received for these products currently differs from the benchmark they are priced against. Future quality differentials are uncertain and a significant increase in the differential could have a material adverse effect on the Company's financial condition.

The Company conducts periodic assessments of the carrying value of its assets in accordance with IFRS Accounting Standards. If crude oil and natural gas forecast prices decline, the carrying value of related property, plant and equipment could be subject to downward revisions, and net earnings could be adversely affected.

Political and International Risk

The Company markets its production in Canada, the United States and internationally. Considering the physical and economic integration of the North American energy markets, any actual or proposed material changes to the international trade environment between Canada and US or other key trade partners, including with respect to governing treaties or trade agreements, or the actual or threatened imposition of trade barriers (including tariffs, quotas, embargoes, safeguards, or other measures), may introduce uncertainty in the markets, have a material effect on commodity prices generally and the crude oil and natural gas prices realized by the Company; increase the cost or reduce the supply of products available to the Company; or require changes to the Company's supply chain or other business practices, any of which have the potential to negatively impact the Company's business, financial condition, and results of operations if the scope or duration of such actions are prolonged.

The tariff environment between the US and Canada continues to evolve. Although the parties have engaged in bilateral trade talks, the US government currently imposes 10% tariffs on all Canadian products not meeting the Canada-United States-Mexico Agreement rules of origin. In addition, recent international developments related to Arctic security indicate the possibility that additional US tariffs may be imposed on various Canadian products if such concerns are not resolved. The recent political volatility in Canada's economic relationship with the United States has caused significant uncertainty over the scope, timing and duration of any actual or proposed tariffs and retaliatory measures, as well as the potential availability of exceptions and exemptions and/or changes to free trade agreements. The effect of trade actions or threatened trade actions may have an impact on the market and pricing received for the Company's products, increase the cost or reduce the availability of products in the Company's supply chain and introduce additional foreign currency volatility. At this time, the duration and impact of instability in the Canada - US trade environment and associated trade actions remains uncertain. The Company will continue to monitor the trade environment and assess the impacts of actual or potential tariffs on its business, financial condition and results.

Environmental Risks

All phases of the crude oil and natural gas business are subject to environmental regulation pursuant to a variety of Canadian, US, UK, European Union, African and other national, federal, provincial, state and municipal laws and regulations as well as international conventions (collectively, "environmental legislation").

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that wells, mines, facility sites and other properties associated with the Company's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations including exploration and development projects and material changes to existing projects may require additional regulatory approvals, including environmental impact assessments or permit applications. Compliance with environmental legislation can require significant expenditures and failure to comply may result in the imposition of fines and penalties or the suspension of operations pending the completion of appropriate remedial measures. The costs of complying with environmental legislation in the future may have a material adverse effect on the Company's business, financial condition and results of operations.

The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulatory compliance, particularly in North America and the North Sea. In respect of its offshore operations, the Company also participates with regulators and industry partners in addressing environmental monitoring and emergency response protocols that are applicable to the Company's operations in these jurisdictions. Environmental monitoring in the oil sands is performed in collaboration with the federal and provincial governments, Indigenous communities and industry, in order to enhance the understanding of the cumulative effects of oil sands development. Existing and anticipated future legislation and regulations may require the Company to address and mitigate the effect of its activities on the environment. Increasingly stringent laws and

regulations may have a material adverse effect on the Company's business, financial condition and results of operations. A summary of key environmental risks is set out below:

• Carbon / GHG Emissions Management

  As part of its evaluation of climate change risk, the Company reviews independent external scenario analyses developed by energy firms and agencies representing a range of global oil and natural gas demand levels through 2050. These external scenario analyses are a tool used by the Company to support business planning, identification of risks and opportunities, and include the consideration of a number of variables and assumptions related to markets, (e.g, economic and social events), commodity prices, carbon prices, policy, regulation, technology development and adoption, energy efficiency and reputation. Under certain stringent low-carbon scenarios, potential demand/supply changes for oil and natural gas products may impact commodity prices; however, it is not currently possible to predict either the timing or precise effects of a potential transition to a lower-carbon economy. Since the Company plans and evaluates opportunities partially on the basis of climate-related assumptions, variations between actual outcomes and expectations may have a material adverse effect on the Company's business, financial condition, results of operations and cash flows. Aspects of climate change risk that have the most potential to influence the Company's business strategy include: future regulatory changes, including government imposed emissions caps, associated compliance costs and reduction targets, access to markets and capital, changes to societal preferences and other factors that may accelerate the transition to alternate fuel sources, reputational risk, and technology development, as described in more detail below.

• Future Regulatory Changes / Compliance Costs / Reduction Targets

  The additional requirements of existing or proposed GHG regulations on the Company's operations may increase capital expenditures and production expenses, including those related to the Company's oil sands projects, planned expansions or new developments. This may have an adverse effect on the Company's financial condition. Accordingly, existing and proposed changes to GHG policies and regulations are considered when making decisions to advance the Company's business strategy. The Company tracks the development of GHG policies and regulations at the international, national, federal and provincial level.

  Various jurisdictions have enacted or are evaluating standards related to the upstream GHG emissions of products (e.g., low carbon fuel standards and methane emission requirements for liquified natural gas), which may affect access to market for hydrocarbons with higher emissions intensity. The regulation of air pollutants to meet ambient air quality objectives (typically as part of regional air zone management) may result in the Company spending additional capital to retrofit equipment in specific regions, depending on future ambient air quality trends.

  The Company's ability to achieve government and corporate emissions or environmental reduction targets could require the development of new technology, the success of which is unknown, as well as significant capital and resources, with the potential that the costs required to achieve targets and goals are materially different from original estimates and expectations. While the intent is to improve efficiency and increase the offering of low carbon energy, the shift in resources and focus to emissions reductions could negatively impact operating results.

• Societal Preferences / Reputational Risk

  Changes in public support for climate action, particularly for oil sands, combined with increased activism and opposition to fossil fuels, which are designed to change consumption habits in order to accelerate the reduction of the global consumption of carbon-based energy, may impact the market for the Company's products and securities and impact its ability to obtain approvals for new projects. The timing and pace of change to a low carbon economy is uncertain and the ability to access insurance and capital may be adversely affected in the event that financial institutions, investors, insurers, rating agencies and/or lenders adopt more restrictive de-carbonization policies. In addition, behavioural changes by the public (such as a shift in transportation preferences or government policy changes which promote the use of electric vehicles or alternative energy sources), may impact the demand for crude oil and the Company's products. Similarly, the Clean Electricity Regulations may impact the demand for natural gas.

• Access to Markets

  The Company's production is transported through various third-party transport systems for sale to markets. The impact of tariffs and/or export taxes on the Company's products, or restricted availability of transport systems could limit the ability to deliver production volumes and adversely affect commodity prices, sales volumes and/or the prices received for the Company's products, projected production growth, operations and cash flows. The Company may also be exposed to greater market risk with the shift to a lower carbon emissions future. These risks may include shifting demand for various energy sources, including increasing demand for renewable energy, and increases in the Company's compliance costs that may not be recoverable in the price of its products, which could delay the development of certain assets. An additional risk includes the potential for restricted access to markets for higher carbon energy sources, which could result in the delay, revocation, or conditions imposed on, regulatory approvals for pipeline projects. These market risks could result in a competitive disadvantage if producers in other jurisdictions are not subject to similar regulatory burdens. There is no certainty that alternative routes or modes of transportation for the Company's production will be available or sufficient to address any gaps caused by operational constraints on applicable pipeline systems.

  • Technology Development

    Regulatory and policy changes to address climate change may require the Company to develop or adopt new sustainable technologies to reduce its environmental footprint and to support the transition to a lower carbon emissions/energy efficient economy at significant cost. In addition, the development, emergence and use of renewable energy sources could affect the demand for the Company's products thereby affecting its competitiveness and profitability. The development and commercialization (including the availability, cost and effectiveness) of new technologies necessary to achieve emissions reductions and environmental improvements is uncertain.

  • Regulatory and Policy Effectiveness

    The Company operates under government regulation and policy for the crude oil and natural gas sector including, land tenure, royalties, taxes, production rates, environmental management, and safety performance. Before proceeding with major projects, the Company must follow various regulatory processes to obtain project approvals and permits. These processes may include Indigenous and other stakeholder consultation, environmental impact assessments and public hearings. The Company's project execution and timelines could be impacted by delays experienced through the regulatory process or by conditions placed on its operations through permit approvals. Regulatory changes may also impact the costs associated with advancing a project or provide opportunities to streamline the regulatory process and/or accelerate timelines to obtain regulatory approval. The Building Canada Act (Canada) ("BCA") which came into force on June 26, 2025, enables the government to streamline federal approval processes to get major projects built faster. The projects anticipated to benefit from a streamlined approval process include ports, railways, energy corridors, critical mineral developments, and clean energy initiatives.

    Further, to facilitate energy collaboration and build a more competitive and sustainable economy, the federal and Alberta governments entered into the MOU. Although the MOU appears supportive of Canada's energy sector, there are no assurances that the parties will reach final agreement on all of the necessary elements required to enable the MOU framework or the environmental laws and regulations negotiated as part of the MOU to have a favourable impact on the oil and natural gas industry in Alberta or the Company, or, if not adopted with the necessary elements, may ultimately have an adverse effect on the Company's business, financial condition and operations.

    Changes in government policy have the potential to impact the certainty and timelines for the regulatory approval process on large energy projects, including increased requirements for Indigenous consultation. Some examples include the federal Net-Zero Emissions Accountability Act (Canada), which implements the United Nations' Declaration on the Rights of Indigenous Peoples Act, and the federal Impact Assessment Act (Canada), the Alberta sub-regional plans supporting caribou recovery, the British Columbia Declaration on the Rights of Indigenous Peoples Act, and the Blueberry River First Nations Implementation Agreement, which was negotiated by the Government of British Columbia to address issues raised in Indigenous litigation (i.e., Yahey vs. British Columbia 2021 (B.C.S.C. 1287), a case regarding the cumulative effects of development on Treaty 8 rights).

  • Tailings Management

    The Alberta Energy Regulator ("AER"), updated Directive 85 - Fluid Tailings Management for Oil Sands Mining Projects ("Directive 85"), in October 2017. Directive 85 establishes performance criteria for tailings operations and sets out the requirements for approval, monitoring and reporting in respect of tailings ponds and tailings management plans.

    The Company continues to implement and adhere to the conditions stipulated in the approved Tailings Management Plans for the Horizon Mine, and Albian's Muskeg River and Jackpine Mines and thereby meet the requirements of the Government of Alberta's Tailings Management Framework (2015) and Directive 85. In addition, the Company obtained approval for the Updated Tailings Management Plans (2023) for Muskeg River and Jackpine Mines. The tailings management plans outline progressive changes to improve performance in tailings management for the full life of the mines as well as the proposed tailings treatment technologies. All three of the Company's mines (Horizon, Muskeg River and Jackpine) continue to meet the expectations outlined within its approved plans. However, in the future, there is the potential risk of exceeding the approved site-specific tailings profiles resulting in the requirement to post additional security under the Mining Financial Security Plan as well as the potential application of a compliance levy. The Company has systems and processes in place for monitoring tailings performance, which uses adaptive management and continuous improvement principle, including research and mitigation technology development to reduce fluid tailings. Through Canada's Oil Sands Innovation Alliance, the innovation arm of Oil Sands Alliance (formerly, Pathways Alliance), technology development is jointly undertaken by all oil sands mine operators to accelerate the commercialization of such technologies.

    The Company's Oil Sands Mining operations continue to plan and execute progressive reclamation activities on the side slopes of its tailings facilities. Muskeg River Mine has advanced the decommissioning and reclamation process for its external tailings facility (South Expansion Area) and is waiting for the final construction completion report to be authorized before finalizing the regulatory requirements with the AER for its deregistration as a dam structure. The South Expansion Area was fully revegetated and reclaimed in 2023 with ongoing reclamation monitoring. Muskeg River Mine's main external tailings facility became inactive at the end of 2025 when the tailings lines were removed. In 2026, the facility will commence the decommissioning process.

• Land Use, Water and Wildlife Management

  Legislation and policies related to land management may affect development and operations risk through changes in regional limits on operating standards for air emissions, water use, land disturbance, reclamation and biodiversity. Land use planning may set aside areas for conservation, parks, or establish operational constraints to protect wetlands, watercourse shorelines, biodiversity and wildlife that may place limits on crude oil and natural gas development. Management frameworks in the Lower Athabasca oil sands area define thresholds for air emissions, surface and ground water quality and quantity that could increase the standards for the operation of facilities. Draft frameworks on biodiversity may establish further limits on development that may limit operations and expansion of facilities. Sub-regional management plans may pose limitations on resource development through limits on infrastructure. In June 2024, the federal government released the draft Nature Accountability Bill to legislate the protection of biodiversity as a method to achieve conservation of 30% of Canada's land area, including the requirement for large companies and financial institutions to monitor, assess and disclose their risks, dependencies and impacts on biodiversity.

  Water licencing, use and release standards are becoming increasingly stringent both in the process of obtaining access to water and to manage it efficiently. Alberta Wetland Policy changes may increase requirements and payments for new project development. Federal and provincial standards governing the treatment and release of water from oil sands projects into the environment are currently under development having regard to applicable regulations governing other mining operations in Canada.

  The Species at Risk Act (Canada) requires the maintenance of habitat for a variety of species. For example, in the case of Woodland Caribou, the regulatory requirements related to undisturbed habitat in addition to minimum herd population may impact plans for crude oil and natural gas expansion. Both the oil and gas and forestry industries are undertaking mitigation measures to maintain habitat function by restricting predator access on seismic lines, reestablishing forests through accelerated reclamation and completing project development planning to minimize caribou disturbance.

  Operational Risk

  Exploring for, producing, mining, extracting, upgrading and transporting crude oil, natural gas and NGLs involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. These activities are subject to a number of hazards and risks which may result in, or contribute to, operational impacts or disruptions, including fires, explosions, spills, blow outs, drought or other water shortages or restrictions, or other unexpected or dangerous conditions causing personal injury, property damage, environmental damage, induced seismicity associated with industrial activities, interruption of operations and loss of production, whether caused by human error, natural or other causes. In addition to the foregoing, the oil sands mining and upgrading operations are also subject to loss of production, potential shutdowns and increased production expenses due to the complexity and integration of the various component parts necessary to mine, extract, process and upgrade bitumen.

  The Company's business also carries risks associated with environmental and safety performance, which are closely scrutinized by governments, the public and the media, and could result in the suspension of or the inability to obtain regulatory approvals and permits, or, in the case of a major incident, fines, civil suits, and/or criminal charges against the Company.

  Extreme weather events and climate conditions, including, but not limited to, floods, droughts, wildfires, and greater variability in seasonal temperatures may pose physical risks to the Company's operations with potential impacts to supply chain and customer/vendor operations or critical infrastructure owned and operated by the Company or third parties. A comprehensive corporate Emergency Management program is in place to coordinate the Company's response to potential accidents and incidents (including extreme weather events). This program includes Emergency Response Plans intended to ensure a prompt initial response and efficient management of situations as they arise.

  The jurisdictions where the Company operates are subject to labour legislation and regulations that, if changed, may impact operations. In addition, labour risk associated with work interruptions and the ability to secure necessary workers may impact the timely and cost effective manner in which projects are completed.

  Reserves Replacement

  The Company's future crude oil and natural gas production, and therefore its cash flows and results of operations, are highly dependent upon success in exploiting its current reserves base and acquiring or discovering additional reserves. Without additions to reserves through exploration, acquisition or development activities, the Company's production will decline over time as reserves are depleted. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent the Company's cash flow is insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the Company's ability to make the necessary capital investments to maintain and expand its crude oil and natural gas reserves will be impaired. In addition, the Company may be unable to find and develop or acquire additional reserves to replace its crude oil and natural gas production at acceptable costs.

  Uncertainty of Reserves Estimates

  There are numerous uncertainties inherent in estimating quantities of reserves, including many factors, both internal and external, beyond the Company's control. Revisions are often necessary as a result of newly acquired technical data, technology improvements, or changes in historical performance, production costs, development costs, product pricing, economic conditions, market availability, or regulatory requirements. In general, estimates of economically recoverable crude oil, natural

  gas and NGLs reserves and the future net revenue therefrom are based upon a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of royalty regimes, higher costs as a result of environmental and other regulation by governmental agencies, estimates of future commodity prices, production costs and the timing and amount of future development expenditures, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable crude oil, natural gas and NGLs reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The Company's actual production, revenues, royalties, taxes and development, abandonment and operating expenditures with respect to its reserves will likely vary from such estimates, and such variances could be material. Estimates of reserves that may be developed in the future are often based upon volumetric calculations, decline curve analysis and upon analogy to actual production history from similar reservoirs and wells. Subsequent evaluation of the same reserves based upon production history will result in variations in the previously estimated reserves.

  Project Risk

  The Company has a variety of exploration, development and construction projects, including environmental mitigation and GHG reduction projects, underway at any given time. Project delays may result in delayed revenue receipts and/or cost overruns may result in projects being uneconomic. The Company's ability to complete projects is dependent on general business and market conditions as well as other factors beyond the Company's control including the availability of skilled labour and workers, the availability and proximity of materials, pipeline capacity, trade measures and tariffs, weather, fires, drought, inflationary cost pressures, legal and regulatory matters (including environmental legislation and government imposed emissions caps), ability to access lands, availability of drilling and other equipment, availability of GHG reduction technologies, and availability of processing capacity.

  Sources of Liquidity

  The ability to fund current and future capital projects and carry out the business plan is dependent on the Company's ability to generate cash flow as well as raise capital in a timely manner under favourable terms and conditions and is impacted by the Company's credit ratings and the condition of the capital and credit markets. Public and stakeholder scrutiny of the Company's stated environmental, sustainability and climate-related targets is increasing. Any failure, or perceived failure, in achieving the Company's stated targets, or the perception that such targets are insufficient or are not achievable within the anticipated timeline, if any, could affect the Company's ability to access cost-effective capital. In addition, changes in credit ratings may affect the ability to, and the associated costs of, entering into ordinary course derivative or hedging transactions, as well as entering into and maintaining ordinary course contracts with customers and suppliers on acceptable terms. The Company also enters into various transactions with counterparties, including joint venture partners, and is subject to credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts, including a failure of counterparties and successors in interest to meet their share of abandonment and reclamation obligations. Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital consisting of cash flows from operating activities, available credit facilities, commercial paper, and access to debt capital markets, to meet obligations as they become due.

  Information Systems

  The Company increasingly relies on information systems ("IS") to effectively operate its business. This includes computer hardware, networks, software, cloud services, mobile applications and systems using artificial intelligence ("AI"). In the ordinary course of business, the Company collects, uses and stores sensitive data, including intellectual property, proprietary information, business information and personal information of the Company's employees, vendors and customers. Despite the Company's security measures in place, IS may still be vulnerable to cyber-incidents (including those performed by malicious nation states, cyber criminals, hacktivists or compromised third parties), disruptions from employee or third-party error, malfeasance, natural disasters, activism, terrorism, war, regional or international conflict.

  Any such incident could result in the loss or disclosure of confidential or private data, asset damage, financial losses, operational disruption, legal claims, regulatory penalties, physical harm to people or the environment, and reputational issues with suppliers, customers, stakeholders and business partners.

  • Cybersecurity

    Cybersecurity risks continue to evolve as threat actors use increasingly advanced tools, including AI. To manage these risks, the Company maintains a comprehensive industry standard cybersecurity framework that includes: IS policies and guidelines, 24-hour managed security monitoring and response, regular cyber assessment of critical third parties, ongoing penetration testing of external systems, annual targeted penetration testing of IS services, incident response readiness drills, routine mandatory cyber education/test programs, multi-factor authentication, data restoration and recovery processes, vulnerability scanning, risk based remediation of vulnerabilities, expedited security patching, in addition to internal accounting and process controls. Cybersecurity oversight is provided by the Audit Committee, which receives updates from management at least semi-annually or more often when required. The Company maintains insurance as part of its risk management program, but such insurance may not cover all damages in connection with a cyber incident, and in some

    instances, certain damages may be excluded from coverage due to the nature of the damages sustained or the causation of the incident.

• Artificial Intelligence

The Company uses AI responsibly to expand employee access to knowledge, deliver data-driven insights and improve efficiency through incremental, cost-justified deployments. The Company will not rely on AI for time-sensitive or production critical processes until controls and evaluations meet necessary standards. Employees must remain actively involved in all AI creation, review, and decision-making while remaining accountable for AI outcomes. Policies, guidelines and technical safeguards are in place to manage AI risks, though these measures cannot eliminate all potential issues. AI related risks and activities are managed with the Company's enterprise risk management system, which is reported on to the Nominating, Governance and Risk Committee at least annually, as well as included in the semi-annual cybersecurity report provided to the Audit Committee. As AI regulations continue to emerge and evolve, compliance may increase costs or limit how AI can be used in Company operations.

Foreign Investments

The Company's foreign investments include risks typically associated with investments in developing countries such as uncertain political, economic, legal and tax environments. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest and other political risks, risk of increases in taxes and governmental royalties, renegotiation of contracts with governmental entities and quasi-governmental agencies, changes in laws and policies governing operations of foreign based companies, including compliance with existing and emerging anti-corruption laws, and other uncertainties arising out of foreign government sovereignty over the Company's international operations. In addition, if a dispute arises in its foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of a court in Canada or the United States.

The Company's arrangement for the exploration and development of crude oil and natural gas properties in Canada and the UK sector of the North Sea differs distinctly from its arrangement for the exploration and development of crude oil and natural gas properties in other foreign jurisdictions. In some foreign countries in which the Company does and may do business in the future, the state generally retains ownership of the minerals and consequently retains control of, and in many cases participates in, the exploration and production of reserves. Accordingly, operations may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses, local content requirements, currency requirements and other charges. In addition, changes in prices and costs of operations, timing of production, and other factors, may affect estimates of crude oil and natural gas reserves quantities and future net revenues attributable to foreign properties in a manner materially different than such changes would affect estimates for Canadian properties. Agreements covering foreign crude oil and natural gas operations also frequently contain provisions obligating the Company to spend specified amounts on exploration and development, or to perform certain operations or forfeit all or a portion of the acreage subject to the contract.

Risk Management Activities

In response to fluctuations in commodity prices, foreign exchange, and interest rates, the Company may periodically utilize various derivative financial instruments and physical sales contracts to manage its exposure under a defined hedging program. The terms of these arrangements may limit the benefit to the Company of favourable changes in these factors and may also result in royalties being paid on a reference price which is higher than the hedged price. There is also increased exposure to counterparty credit risk.

Dividends and Share Repurchases

The payment of future dividends and the repurchase of Company common shares is dependent on, among other things, its financial condition and other business factors considered relevant by the Board of Directors including prevailing economic conditions, the Company's anticipated requirements to fund operations and projects, debt servicing obligations and compliance with applicable regulatory and stock exchange requirements. The dividend policy and the free cash flow(1) allocation policy (which allocates returns to Company shareholders through share repurchases after capital requirements and the payment of dividends), each undergo periodic review by the Board of Directors and are subject to change.

Other Business Risks

Other business risks which may negatively impact the Company's financial condition include regulatory issues, risk of increases in government taxes and changes to royalty regimes, risk of litigation, risk to the Company's reputation resulting from operational activities that may cause personal injury, property damage or environmental damage, labour risk associated with securing the workers necessary to complete capital projects in a timely and cost effective manner, severe weather conditions, the timing and success of integrating the business and operations of acquired companies and businesses, and the dependency on third party operators for certain of the Company's assets.

(1) The term "free cash flow" is a Non-GAAP Measure. Refer to the "Advisory" section of this AIF for further details regarding Non-GAAP Financial Measures.

In addition, epidemics or pandemics have the potential to disrupt the Company's operations, projects, and financial condition through the disruption of the local or global supply chain and transportation services, or the loss of workers resulting from quarantines that affect the Company's labour pools in local communities, workforce camps or operating sites or that are instituted by local health authorities as a precautionary measure, any of which may require the Company to temporarily reduce or shutdown its operations depending on the extent and severity of a potential outbreak and the areas or operations impacted. However, during an epidemic or pandemic, the Company's operations may be designated as "essential services" by applicable government authorities (as was the case for the COVID-19 pandemic), which permitted operations to continue in areas that may have otherwise been impacted by government imposed lockdown measures. Depending on the severity of an outbreak, the timing and availability of vaccines and the speed of vaccine distribution, a large scale epidemic or pandemic could impact the international demand for commodities and have a corresponding impact on the prices realized by the Company for its products, which could have a material adverse effect on the Company's financial condition.

Some of the Company's assets are held in one or more corporate subsidiaries or partnerships. In the event of the liquidation of any corporate subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees, prior to being used to repay the indebtedness of the Company.

Competition Act

On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement, which impacted environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. These amendments include substantial financial penalties and, effective June 20, 2025, a private right of action which will permit private parties to seek an order from the Competition Tribunal under the deceptive marketing practices provisions. Subsequently, on November 4, 2025, the federal government tabled the 2025 Budget, which proposed further amendments to the Competition Act, namely removing the requirement that businesses substantiate their environmental representations about a business or business activity based on an internationally recognized methodology, and eliminating private rights of action under the revised business-activity greenwashing provision. Uncertainty surrounding the interpretation and enforcement of this legislation, which includes the status of any proposed or future amendments, may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results. To mitigate its exposure to claims, the Company has taken various steps, including employee training, adopting internal procedures for review of its public statements and the removal of certain public-facing communications containing environmental and climate communications. Although the Company continues to advance its environmental projects and to improve its performance, the Company has adopted a conservative approach to its public representations pending further guidance from the Competition Bureau, the Competition Tribunal and the courts.

Modern Slavery Act

On January 1, 2024, the Fighting Against Forced Labour and Child Labour in Supply Chains Act (the "Modern Slavery Act") came into force in Canada. The Modern Slavery Act obligates the Company to publish an annual modern slavery report detailing steps regarding the previous year's efforts to mitigate the risk of forced labour used at any step in its supply chain, including production of goods in Canada or elsewhere or of goods imported into Canada. There is a risk that the Company's supply chain may actually use or be alleged to have used forced labour or child labour, and there may be difficulty in gathering sufficient information from suppliers. The Company continues to assess this risk and determine what measures can be put in place to mitigate any identified exposures, which may affect the Company's operational efficiency, results of operations, financial condition, or reputation. For further information, please refer to the Company's 2024 Modern Slavery Annual Report, published at https://www.cnrl.com/about-us/code-of-conduct-and-human-rights/. This Report is not incorporated by reference into this AIF.

For additional details regarding the Company's risks and uncertainties, refer to the Company's annual MD&A for the year ended December 31, 2025, dated March 4, 2026.

Form 51-101F1 Statement of Reserves Data and Other Information

For the year ended December 31, 2025, the Company retained Independent Qualified Reserves Evaluators ("IQRE"), Sproule International Limited ("Sproule ERCE") and GLJ Ltd. ("GLJ"), to evaluate and review all of the Company's proved and proved plus probable reserves with an effective date of December 31, 2025 and a preparation date of February 9, 2026. Sproule ERCE evaluated and reviewed the North America and International light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal bitumen, natural gas and NGLs reserves. GLJ evaluated the Oil Sands Mining and Upgrading mining bitumen and SCO reserves. The evaluations and reviews were conducted and prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and disclosed in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") requirements.

The Reserves Committee of the Company's Board of Directors has met with and carried out independent due diligence procedures with each of the Company's IQREs to review the qualifications of and procedures used by each IQRE in determining the estimate of the Company's quantities and related net present value of future net revenue of the remaining reserves.

In 2025, the Company completed the AOSP asset swap with Shell Canada Limited and affiliates. As a result of the transaction, the Company acquired the remaining 10% working interest in the AOSP mines in exchange for a 10% working interest in the non-operated Scotford Upgrader and Quest. The Company now owns a 100% working interest in the AOSP mines and retains an 80% working interest in the non-operated Scotford Upgrader and Quest. Due to the difference of ownership interest between the AOSP mines and Scotford Upgrader and Quest and in accordance with NI 51-101 requirements, 80% of the reserves and sales volumes are disclosed as SCO and the remaining 20% are disclosed as mining bitumen.

In 2025, it was also determined that the North Sea reporting jurisdiction was no longer economic and the Company de-booked associated crude oil and natural gas reserves in such reporting jurisdiction as at December 31, 2025. Notwithstanding this decision, four crude oil fields remained in production at the end of 2025 and will continue to produce during portions of the decommissioning phase of these assets. As there are no reserves to disclose, the North Sea reporting jurisdiction has been removed from certain tables in the following disclosure.

The Company annually discloses net proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current costs in accordance with United States Financial Accounting Standards Board Topic 932 "Extractive Activities - Oil and Gas" in the Company's annual report on Form 40-F filed with the SEC in the "Supplementary Oil and Gas Information" section of the Company's 2025 Annual Report, which is incorporated herein by reference.

Information in the reserves data tables may not add due to rounding. BOE values and crude oil and natural gas metrics may not calculate due to rounding. The estimates of future net revenue presented in the tables below do not represent the fair market value of the reserves. There is no assurance that the price and cost assumptions contained in the forecast case will be attained and variances could be material. The estimates of recovery and reserves of crude oil, natural gas and NGLs provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGLs reserves may be greater or less than the estimate provided herein. Refer to "Special Note Regarding Forward-Looking Statements" and "Special Note Regarding Currency, Financial Information, Production and Reserves" in the "Advisory"; and the "Risk Factors" section of this AIF. Oil and Gas Reserves Tables and Notes Summary of Company Gross Reserves As of December 31, 2025 Forecast Prices and Costs

Light and Medium Crude Oil	Primary Heavy Crude Oil	Pelican Lake Heavy Crude Oil	Thermal Bitumen	Mining Bitumen	Synthetic Crude Oil	Natural Gas	Natural Gas Liquids	Barrels of Oil Equivalent
(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(Bcf)	(MMbbl)	(MMBOE)
North America Proved Developed Producing 120	130	188	684	835	7,043	5,859	229	10,206
Developed Non-Producing 2	6	-	42	-	-	272	13	109
Undeveloped 141	92	55	2,603	14	91	11,868	575	5,548
Total Proved 264	228	243	3,330	849	7,134	17,999	817	15,864
Probable 107	105	107	1,845	46	554	9,965	404	4,828
Total Proved plus Probable 371	333	349	5,175	895	7,688	27,964	1,221	20,693

North Sea

Proved

Developed Producing Developed Non-Producing Undeveloped	- - - - - - - - -
Total Proved	- - -
Probable	- - -
Total Proved plus Probable	- - -
Offshore Africa Proved

Developed Producing	1						2		1
Developed Non-Producing	26						-		26
Undeveloped	19						5		19
Total Proved	45						7		46
Probable	11						4		11
Total Proved plus Probable	56						11		57
Total Company Proved Developed Producing	121	130	188	684	835	7,043	5,861	229	10,207
Developed Non-Producing	28	6	-	42	-	-	272	13	135
Undeveloped	160	92	55	2,603	14	91	11,873	575	5,568
Total Proved	309	228	243	3,330	849	7,134	18,006	817	15,910
Probable	118	105	107	1,845	46	554	9,969	404	4,840
Total Proved plus Probable	427	333	349	5,175	895	7,688	27,974	1,221	20,750

Summary of Company Net Reserves As of December 31, 2025 Forecast Prices and Costs

Light and Medium Crude Oil	Primary Heavy Crude Oil	Pelican Lake Heavy Crude Oil	Thermal Bitumen	Mining Bitumen	Synthetic Crude Oil	Natural Gas	Natural Gas Liquids	Barrels of Oil Equivalent
(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(Bcf)	(MMbbl)	(MMBOE)
North America Proved Developed Producing 104	107	150	518	649	5,831	5,308	185	8,427
Developed Non-Producing 2	5	-	32	-	-	246	11	91
Undeveloped 112	76	43	1,970	4	45	10,400	452	4,436
Total Proved 218	188	193	2,520	653	5,876	15,954	648	12,955
Probable 83	83	77	1,371	31	440	8,511	291	3,794
Total Proved plus Probable 301	272	270	3,891	684	6,315	24,465	939	16,749

North Sea

Proved

Developed Producing Developed Non-Producing Undeveloped	- - - - - - - - -
Total Proved	- - -
Probable	- - -
Total Proved plus Probable	- - -
Offshore Africa Proved

Developed Producing	1						2		1
Developed Non-Producing	24						-		24
Undeveloped	14						4		15
Total Proved	39						6		40
Probable	8						3		8
Total Proved plus Probable	47						9		48
Total Company Proved Developed Producing	104	107	150	518	649	5,831	5,310	185	8,428
Developed Non-Producing	26	5	-	32	-	-	246	11	116
Undeveloped	127	76	43	1,970	4	45	10,403	452	4,451
Total Proved	257	188	193	2,520	653	5,876	15,960	648	12,995
Probable	91	83	77	1,371	31	440	8,514	291	3,803
Total Proved plus Probable	348	272	270	3,891	684	6,315	24,473	939	16,797

Reconciliation of Company Gross Reserves As of December 31, 2025 Forecast Prices and Costs TOTAL PROVED

	Crude Oil	Crude Oil	Crude Oil	Bitumen	Bitumen	Crude Oil	Gas	Liquids	Equivalent
	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(Bcf)	(MMbbl)	(MMBOE)
December 31, 2024	190	219	255	3,312	-	7,663	16,880	713	15,165
Discoveries	-	-	-	-	-	-	-	-	-
Extensions	16	12	-	66	-	-	113	8	121
Infill Drilling	2	17	1	9	-	-	191	36	97
Improved Recovery	-	1	3	-	-	2	-	-	6
Acquisitions	68	-	-	-	427	-	1,153	74	760
Dispositions	-	-	-	-	-	-	-	-	-
Economic Factors	(4)	(4)	(3)	-	-	-	(99)	(4)	(32)
Technical Revisions	15	15	2	43	426	(328)	687	28	316
Production	(22)	(32)	(16)	(100)	(4)	(202)	(926)	(38)	(568)
December 31, 2025	264	228	243	3,330	849	7,134	17,999	817	15,864
North Sea
December 31, 2024	6						3		7
Discoveries	-						-		-
Extensions	-						-		-
Infill Drilling	-						-		-
Improved Recovery	-						-		-
Acquisitions	-						-		-
Dispositions	-						-		-
Economic Factors	-						-		-
Technical Revisions	(3)						(2)		(3)
Production	(3)						(1)		(3)
December 31, 2025	-						-		-
Offshore Africa
December 31, 2024	56						20		60
Discoveries	-						-		-
Extensions	-						-		-
Infill Drilling	-						-		-
Improved Recovery	-						-		-
Acquisitions	-						-		-
Dispositions	-						-		-
Economic Factors	-						-		-
Technical Revisions	(10)						(11)		(12)
Production	(1)						(2)		(2)
December 31, 2025	45						7		46
Total Company
December 31, 2024	252	219	255	3,312	-	7,663	16,904	713	15,231
Discoveries	-	-	-	-	-	-	-	-	-
Extensions	16	12	-	66	-	-	113	8	121
Infill Drilling	2	17	1	9	-	-	191	36	97
Improved Recovery	-	1	3	-	-	2	-	-	6
Acquisitions	68	-	-	-	427	-	1,153	74	760
Dispositions	-	-	-	-	-	-	-	-	-
Economic Factors	(4)	(4)	(3)	-	-	-	(99)	(4)	(32)
Technical Revisions	1	15	2	43	426	(328)	674	28	300
Production	(26)	(32)	(16)	(100)	(4)	(202)	(930)	(38)	(573)
December 31, 2025	309	228	243	3,330	849	7,134	18,006	817	15,910

North America

Light and Medium

Primary Heavy

Pelican Lake

Heavy

Thermal

Mining

Synthetic

Natural

Natural

Gas

Barrels of Oil

TOTAL PROBABLE

North America

Light and Medium

Primary Heavy

Pelican Lake

Heavy

Thermal

Mining

Synthetic

Natural

Natural

Gas

Barrels of Oil

	Crude Oil	Crude Oil	Crude Oil	Bitumen	Bitumen	Crude Oil	Gas	Liquids	Equivalent
	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(Bcf)	(MMbbl)	(MMBOE)
December 31, 2024	76	99	105	1,878	-	593	10,236	403	4,859
Discoveries	-	-	-	-	-	-	-	-	-
Extensions	6	8	-	23	-	-	54	4	50
Infill Drilling	-	9	1	2	-	-	134	18	53
Improved Recovery	-	-	1	-	-	-	-	-	2
Acquisitions	31	-	-	-	23	-	315	21	127
Dispositions	-	-	-	-	-	-	-	-	-
Economic Factors	(1)	(1)	1	-	-	-	-	-	-
Technical Revisions	(6)	(10)	(2)	(58)	23	(39)	(775)	(42)	(262)
Production	-	-	-	-	-	-	-	-	-
December 31, 2025	107	105	107	1,845	46	554	9,965	404	4,828
North Sea
December 31, 2024	1						1		1
Discoveries	-						-		-
Extensions	-						-		-
Infill Drilling	-						-		-
Improved Recovery	-						-		-
Acquisitions	-						-		-
Dispositions	-						-		-
Economic Factors	-						-		-
Technical Revisions	(1)						(1)		(1)
Production	-						-		-
December 31, 2025	-						-		-
Offshore Africa
December 31, 2024	16						15		19
Discoveries	-						-		-
Extensions	-						-		-
Infill Drilling	-						-		-
Improved Recovery	-						-		-
Acquisitions	-						-		-
Dispositions	-						-		-
Economic Factors	-						-		-
Technical Revisions	(6)						(11)		(8)
Production	-						-		-
December 31, 2025	11						4		11
Total Company
December 31, 2024	94	99	105	1,878	-	593	10,252	403	4,879
Discoveries	-	-	-	-	-	-	-	-	-
Extensions	6	8	-	23	-	-	54	4	50
Infill Drilling	-	9	1	2	-	-	134	18	53
Improved Recovery	-	-	1	-	-	-	-	-	2
Acquisitions	31	-	-	-	23	-	315	21	127
Dispositions	-	-	-	-	-	-	-	-	-
Economic Factors	(1)	(1)	1	-	-	-	-	-	-
Technical Revisions	(13)	(10)	(2)	(58)	23	(39)	(788)	(42)	(271)
Production	-	-	-	-	-	-	-	-	-
December 31, 2025	118	105	107	1,845	46	554	9,969	404	4,840

TOTAL PROVED PLUS PROBABLE

Light and	Primary	Pelican Lake					Natural	Barrels
Medium	Heavy	Heavy	Thermal	Mining	Synthetic	Natural	Gas	of Oil

North America

	Crude Oil	Crude Oil	Crude Oil	Bitumen	Bitumen	Crude Oil	Gas	Liquids	Equivalent
	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(Bcf)	(MMbbl)	(MMBOE)
December 31, 2024	266	318	360	5,190	-	8,255	27,116	1,116	20,024
Discoveries	-	-	-	-	-	-	-	-	-
Extensions	22	20	-	89	-	-	167	12	171
Infill Drilling	2	26	3	11	-	-	325	54	149
Improved Recovery	-	1	4	-	-	2	-	-	7
Acquisitions	99	-	-	-	450	-	1,469	95	888
Dispositions	-	-	-	-	-	-	-	-	-
Economic Factors	(5)	(5)	(2)	-	-	-	(99)	(4)	(32)
Technical Revisions	9	5	-	(15)	449	(367)	(88)	(14)	54
Production	(22)	(32)	(16)	(100)	(4)	(202)	(926)	(38)	(568)
December 31, 2025	371	333	349	5,175	895	7,688	27,964	1,221	20,693
North Sea
December 31, 2024	7						5		8
Discoveries	-						-		-
Extensions	-						-		-
Infill Drilling	-						-		-
Improved Recovery	-						-		-
Acquisitions	-						-		-
Dispositions	-						-		-
Economic Factors	-						-		-
Technical Revisions	(4)						(4)		(4)
Production	(3)						(1)		(3)
December 31, 2025	-						-		-
Offshore Africa
December 31, 2024	73						36		79
Discoveries Extensions Infill Drilling	- - -						- - -		- - -
Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions	- - - - (16)						- - - - (22)		- - - - (20)
Production	(1)						(2)		(2)
December 31, 2025	56						11		57
Total Company
December 31, 2024	346	318	360	5,190	-	8,255	27,156	1,116	20,110
Discoveries	-	-	-	-	-	-	-	-	-
Extensions	22	20	-	89	-	-	167	12	171
Infill Drilling	2	26	3	11	-	-	325	54	149
Improved Recovery	-	1	4	-	-	2	-	-	7
Acquisitions	99	-	-	-	450	-	1,469	95	888
Dispositions	-	-	-	-	-	-	-	-	-
Economic Factors	(5)	(5)	(2)	-	-	-	(99)	(4)	(32)
Technical Revisions	(11)	5	-	(15)	449	(367)	(114)	(14)	29
Production	(26)	(32)	(16)	(100)	(4)	(202)	(930)	(38)	(573)
December 31, 2025	427	333	349	5,175	895	7,688	27,974	1,221	20,750

Notes to Reserves Tables

1. "Company gross reserves" are the Company's working interest share of reserves before deduction of royalties and without including any royalty interests of the Company.

2. "Company net reserves" are the company gross reserves less all royalties payable to others plus royalties receivable from others.

3. References to "light and medium crude oil" means "light crude oil and medium crude oil combined".

4. "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 analysis of drilling, geological, geophysical, and engineering data, with the use of established technology and under specified economic conditions which are generally accepted as being reasonable.

   Reserves are classified according to the degree of certainty associated with the estimates:

   • "Proved reserves" are those reserves which 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.

   • "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.

     Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:

   • "Developed reserves" are reserves that are expected to be recovered from (i) existing wells and installed facilities or, if the facilities have not been installed, that would involve a low expenditure (compared to the cost of drilling a well) to put the reserves on production, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. The developed category may be subdivided into producing and non-producing.

   • "Undeveloped reserves" are reserves that are expected to be recovered from known accumulations with new wells on undrilled acreage, or from existing wells where significant expenditures are required for the completion of these wells or for the installation of processing and gathering facilities prior to the production of these reserves. Reserves on undrilled acreage are limited to those drilling units directly offsetting development spacing areas that are reasonably certain of production when drilled unless reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

5. The reserves evaluation involved data supplied by the Company with respect to geological and engineering data, product price adjustments for product quality, heating value and transportation, interests owned, royalties payable, production costs, capital costs and contractual commitments. This data was found by the IQRE to be reasonable.

6. Reserves reconciliation change category definitions:

   • "Discoveries" means additions to reserves in reservoirs where no reserves were previously booked.

   • "Extensions" means additions to reserves resulting from step-out drilling or recompletions.

   • "Infill Drilling" means additions to reserves resulting from drilling or recompletions within the known boundaries of a reservoir.

   • "Improved Recovery" means additions to reserves resulting from the implementation of improved recovery schemes.

   • "Economic Factors" means changes primarily due to price forecasts.

   • "Technical Revisions" include changes in previous estimates resulting from new technical data or revised interpretations and changes in operating costs, capital costs and offsets to product reference pricing.

7. 2025 reserves reconciliation highlights:

   Total Proved Crude Oil, Thermal Bitumen, Mining Bitumen, SCO and NGLs reserves increased by 496 MMbbl:

   • Extensions: Increase of 103 MMbbl primarily due to extension drilling/future offset additions at various Thermal Bitumen, Light Crude Oil, Primary Heavy Crude Oil and natural gas (NGLs) properties.

   • Infill Drilling: Increase of 65 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs), Primary Heavy Crude Oil, Thermal Bitumen, Light Crude Oil and Pelican Lake Heavy Crude Oil properties.

   • Improved Recovery: Increase of 6 MMbbl primarily due to increased recovery at Pelican Lake Heavy Crude Oil, Oil Sands Mining and Upgrading (SCO) and various Primary Heavy Crude Oil properties.

   • Acquisitions: Increase of 568 MMbbl primarily due to acquisitions at Oil Sands Mining and Upgrading (Mining Bitumen), various natural gas (NGLs) and Light Crude Oil properties.

   • Economic Factors: Decrease of 15 MMbbl due to changes in product pricing.

     • Technical Revisions: Increase of 188 MMbbl primarily due to improved performance at Oil Sands Mining and Upgrading (Mining Bitumen and SCO), various Thermal Bitumen, natural gas (NGLs), Primary Heavy Crude Oil, Pelican Lake Heavy Crude Oil and Light Crude Oil properties, partially offset by a category transfer at Oil Sands Mining and Upgrading from SCO to Bitumen Mining.

     • Production: Decrease of 418 MMbbl.

       Total Proved Natural Gas reserves increased by 1,102 Bcf:

     • Extensions: Increase of 113 Bcf primarily due to extension drilling/future offset additions in the Montney and other unconventional formations of northwest Alberta and northeast British Columbia.

     • Infill Drilling: Increase of 191 Bcf primarily due to infill drilling/future offset additions in the Montney and other unconventional formations of northwest Alberta and northeast British Columbia.

     • Acquisitions: Increase of 1,153 Bcf primarily due to acquisitions at various Natural Gas properties.

     • Economic Factors: Decrease of 99 Bcf due to lower product pricing.

     • Technical Revisions: Increase of 674 Bcf primarily due to positive revisions in various North America core areas as a result of improved performance and category transfers from probable to proved reserves.

     • Production: Decrease of 930 Bcf.

       Total Proved plus Probable Crude Oil, Thermal Bitumen, Mining Bitumen, SCO and NGLs reserves increased by 504 MMbbl:

     • Extensions: Increase of 143 MMbbl primarily due to extension drilling/future offset additions at various Thermal Bitumen, Light Crude Oil, Primary Heavy Crude Oil and natural gas (NGLs) properties.

     • Infill Drilling: Increase of 95 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs), Primary Heavy Crude Oil, Thermal Bitumen, Pelican Lake Heavy Crude Oil and Light Crude Oil properties.

     • Improved Recovery: Increase of 7 MMbbl primarily due to increased recovery at Pelican Lake Heavy Crude Oil, Oil Sands Mining and Upgrading (SCO) and various Primary Heavy Crude Oil properties.

     • Acquisitions: Increase of 643 MMbbl primarily due to acquisitions at Oil Sands Mining and Upgrading (Mining Bitumen), various Light Crude Oil and natural gas (NGLs) properties.

     • Economic Factors: Decrease of 15 MMbbl due to changes in product pricing.

     • Technical Revisions: Increase of 48 MMbbl primarily due to mine plan changes at Oil Sands Mining and Upgrading (Mining Bitumen and SCO), and performance at various Primary Heavy Crude Oil properties, partially offset by decreased performance at various Light Crude Oil, Thermal Bitumen and natural gas (NGLs) properties, and by a category transfer at Oil Sands Mining and Upgrading from SCO to Mining Bitumen.

     • Production: Decrease of 418 MMbbl.

       Total Proved plus Probable Natural Gas reserves increased by 818 Bcf:

     • Extensions: Increase of 167 Bcf primarily due to extension drilling/future offset additions in the Montney and other unconventional formations of northwest Alberta and northeast British Columbia.

     • Infill Drilling: Increase of 325 Bcf primarily due to infill drilling/future offset additions in the Montney and other unconventional formations of northwest Alberta and northeast British Columbia.

     • Acquisitions: Increase of 1,469 Bcf primarily due to acquisitions at various Natural Gas properties.

     • Economic Factors: Decrease of 99 Bcf due to lower product pricing.

     • Technical Revisions: Decrease of 114 Bcf primarily due to negative revisions at various Natural Gas properties.

     • Production: Decrease of 930 Bcf.

8. A report on reserves data by the IQREs is provided in Schedule "A" to this AIF. A report by the Company's management and directors on crude oil, natural gas and NGLs reserves disclosure is provided in Schedule "B" to this AIF.

Future Net Revenue Tables and Notes

The following tables summarize the future net revenue as of December 31, 2025 using forecast prices and costs. Abandonment, Decommissioning and Reclamation ("ADR") costs included in the calculation of future net revenue consist of both the Company's total North America and Offshore Africa Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as of December 31, 2025 and forecast estimates of ADR costs attributable to future development activity.

Summary of Net Present Values of Future Net Revenue Before Income Taxes As of December 31, 2025 Forecast Prices and Costs

Unit Value Discounted at

10%/year

($ millions)	Discount @ 0%	Discount @ 5%	Discount @ 10%	Discount @ 15%	Discount @ 20%	($/BOE)
North America
Proved
Developed Producing	447,601	187,808	110,334	78,141	61,182	13.09
Developed Non-Producing	3,196	1,465	920	674	535	10.08
Undeveloped	179,363	83,964	45,436	27,356	17,785	10.24
Total Proved	630,159	273,238	156,690	106,170	79,502	12.10
Probable	199,626	68,282	32,848	19,793	13,705	8.66
Total Proved plus Probable	829,786	341,519	189,539	125,963	93,207	11.32
Offshore Africa
Proved
Developed Producing	(454)	(296)	(220)	(181)	(160)	(254.23)
Developed Non-Producing	1,050	818	651	527	432	26.68
Undeveloped	1,239	892	659	498	381	44.40
Total Proved	1,835	1,413	1,091	844	653	27.19
Probable	767	533	382	282	213	45.83
Total Proved plus Probable	2,602	1,946	1,473	1,126	867	30.40
Total Company
Proved
Developed Producing	447,147	187,512	110,114	77,960	61,023	13.07
Developed Non-Producing	4,246	2,283	1,572	1,201	967	13.58
Undeveloped	180,602	84,856	46,096	27,853	18,166	10.36
Total Proved	631,994	274,651	157,781	107,014	80,156	12.14
Probable	200,394	68,814	33,231	20,075	13,918	8.74
Total Proved plus Probable	832,388	343,465	191,012	127,089	94,074	11.37

Summary of Net Present Values of Future Net Revenue After Income Taxes As of December 31, 2025 Forecast Prices and Costs

($ millions)	Discount @ 0%	Discount @ 5%	Discount @ 10%	Discount @ 15%	Discount @ 20%
North America
Proved
Developed Producing	348,517	147,295	87,094	61,977	48,694
Developed Non-Producing	2,590	1,132	697	504	396
Undeveloped	137,593	63,572	33,795	19,890	12,574
Total Proved	488,700	211,999	121,586	82,371	61,663
Probable	153,006	52,118	24,966	14,985	10,342
Total Proved plus Probable	641,706	264,117	146,552	97,355	72,005
Offshore Africa
Proved
Developed Producing	(456)	(299)	(222)	(183)	(162)
Developed Non-Producing	962	750	597	482	395
Undeveloped	936	679	505	382	292
Total Proved	1,442	1,131	880	682	525
Probable	574	399	286	211	159
Total Proved plus Probable	2,016	1,530	1,167	893	684
Total Company
Proved
Developed Producing	348,061	146,996	86,872	61,794	48,532
Developed Non-Producing	3,552	1,882	1,294	986	790
Undeveloped	138,529	64,251	34,301	20,272	12,866
Total Proved	490,142	213,130	122,466	83,052	62,188
Probable	153,581	52,517	25,252	15,196	10,501
Total Proved plus Probable	643,722	265,647	147,718	98,248	72,689

Total Future Net Revenue (Undiscounted) As of December 31, 2025 Forecast Prices and Costs

North America Offshore Africa Total Company

($ millions)	Total Proved	Total Proved plus Probable	Total Proved	Total Proved plus Probable	Total Proved	Total Proved plus Probable
Revenue	1,515,698	1,923,661	4,157	5,024	1,519,855	1,928,685
Royalties	285,418	375,998	142	183	285,561	376,181
Production Costs	471,315	564,057	1,042	1,030	472,357	565,088
Development Costs	105,432	129,200	643	705	106,074	129,906
ADR Costs for Future Development	1,518	2,159	33	42	1,552	2,201
Future Net Revenue Before Income Taxes Excluding	652,015	852,246	2,296	3,063	654,311	855,309
ADR Costs for Existing Development (Equivalent to
the Financial Statement ARO)
ADR Costs for Existing Development (Equivalent to	21,855	22,460	462	462	22,317	22,921
the Financial Statement ARO)
Future Net Revenue Before Income Taxes Including	630,159	829,786	1,835	2,602	631,994	832,388
ADR Costs for Existing Development (Equivalent to
the Financial Statement ARO)
Income Taxes	141,460	188,080	393	586	141,852	188,665
Future Net Revenue After Income Taxes	488,700	641,706	1,442	2,016	490,142	643,722

Future Net Revenue By Product Type As of December 31, 2025 Forecast Prices and Costs Total Proved

Product Type

Future Net Revenue Before Income Taxes (discounted at 10%/year)

($ millions)

Unit Value ($/BOE)

Light and Medium Crude Oil	8,733	16.00
(including solution gas and other by-products)
Primary Heavy Crude Oil	4,057	20.89
(including solution gas)
Pelican Lake Heavy Crude Oil	3,219	16.66
(including solution gas)
Thermal Bitumen	35,726	14.18
Mining Bitumen	6,086	9.32
Synthetic Crude Oil	86,101	14.65
Natural Gas	18,434	6.12
(including by-products but excluding solution gas and by-products from crude oil wells)
Total	162,356	12.49
Excluding ADR Costs for Existing Development
(Equivalent to the Financial Statement ARO)
ADR Costs for Existing Development	(4,575)
(Equivalent to the Financial Statement ARO)
Total Including ADR Costs for Existing Development (Equivalent to the Financial Statement ARO)	157,781	12.14

Total Proved plus Probable

Product Type

Future Net Revenue Before Income Taxes (discounted at 10%/year)

($ millions)

Unit Value ($/BOE)

Light and Medium Crude Oil	12,339	16.70
(including solution gas and other by-products)
Primary Heavy Crude Oil	6,055	21.65
(including solution gas)
Pelican Lake Heavy Crude Oil	4,281	15.83
(including solution gas)
Thermal Bitumen	44,943	11.55
Mining Bitumen	6,527	9.54
Synthetic Crude Oil	93,211	14.76
Natural Gas	28,277	6.12
(including by-products but excluding solution gas and by-products from crude oil wells)
Total	195,633	11.65
Excluding ADR Costs for Existing Development
(Equivalent to the Financial Statement ARO)
ADR Costs for Existing Development	(4,621)
(Equivalent to the Financial Statement ARO)
Total Including ADR Costs for Existing Development (Equivalent to the Financial Statement ARO)	191,012	11.37

Notes to Future Net Revenue Tables

1. Abandonment, Decommissioning and Reclamation ("ADR") costs included in the calculation of the future net revenue consist of both the Company's total North America and Offshore Africa Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as of December 31, 2025 and forecast estimates of ADR costs attributable to future development activity. The Company's total North America and Offshore Africa ARO included in the reserves future net revenue is escalated at the rate of inflation described in the "Pricing Assumptions" section of this AIF.

2. For reserves in Canada, future net revenue includes carbon cost compliance in accordance with provincial GHG policies. In British Columbia and Manitoba, carbon costs will reach $170/tonne in 2030, in Alberta, $130/tonne in 2028 (as informed by the November 2025 MOU between the federal and Alberta governments), and in Saskatchewan there is currently no carbon pricing in effect. Refer to the "Regulatory Matters" section of this AIF for further details on GHG policies.

3. Unit values ($/BOE) are based on company net reserves.

4. After-tax net present values consider the Company's existing tax pool balances and current tax regulations and do not represent an estimate of the value at the consolidated entity level, which may be significantly different. For information at the consolidated entity level, refer to the Company's Consolidated Financial Statements for the year ended December 31, 2025 and the annual MD&A for the year ended December 31, 2025, dated March 4, 2026.

5. Future net revenue is prior to provision for interest, general and administrative expenses, and the impact of any risk management activities.

Pricing Assumptions

The crude oil, natural gas and NGLs reference pricing and the inflation and exchange rates used in the preparation of reserves and related future net revenue estimates are as per the 3-consultant-average of price forecasts developed by Sproule ERCE, GLJ and McDaniel & Associates Consultants Ltd. ("McDaniel"), dated December 31, 2025. The following is a summary of the 3-consultant-average price forecast. All prices increase at a rate of 2% per year after 2030.

		2026	2027	2028	2029	2030
Crude Oil and NGLs WTI	US$/bbl	59.92	65.10	70.28	71.93	73.37
WCS	C$/bbl	65.13	70.43	76.90	78.71	80.29
Canadian Light Sweet	C$/bbl	77.54	83.60	90.17	92.32	94.17
Cromer LSB	C$/bbl	75.09	81.56	86.95	89.19	90.98
Edmonton C5+	C$/bbl	80.01	86.19	92.83	95.04	96.94
Brent	US$/bbl	63.92	69.13	74.36	76.10	77.62
Natural Gas AECO	C$/MMBtu	3.00	3.30	3.49	3.58	3.65
BC Westcoast Station 2	C$/MMBtu	2.66	3.07	3.25	3.34	3.41
Henry Hub	US$/MMBtu	3.74	3.78	3.85	3.93	4.01

Notes to Pricing Assumptions Table

1. Reference pricing definitions:

   • "WTI" refers to the price of West Texas Intermediate crude oil at Cushing, Oklahoma.

   • "WCS" refers to Western Canadian Select, a blend of heavy crude oils and bitumen with sweet synthetic and condensate diluents at Hardisty, Alberta; reference price used in the preparation of primary heavy crude oil, Pelican Lake heavy crude oil, thermal bitumen and mining bitumen reserves.

   • "Canadian Light Sweet" refers to the price of light gravity (40o API), low sulphur content Mixed Sweet Blend (MSW) crude oil at Edmonton, Alberta; reference price used in the preparation of light and medium crude oil and SCO reserves.

   • "Cromer LSB" refers to the price of light sour blend (35o API) physical crude oil at Cromer, Manitoba; reference price used in the preparation of light and medium crude oil in SE Saskatchewan and SW Manitoba reserves.

   • "Edmonton C5+" refers to pentanes plus at Edmonton, Alberta; reference price used in the preparation of NGLs reserves; also used in determining the diluent costs associated with primary heavy crude oil and thermal bitumen reserves.

   • "Brent" refers to the benchmark price for European, African and Middle Eastern crude oil; reference price used in the preparation of Offshore Africa light crude oil reserves.

     • "AECO" refers to the Alberta natural gas trading price at the AECO-C hub in southeast Alberta; reference price used in the preparation of North America (excluding British Columbia) natural gas reserves.

     • "BC Westcoast Station 2" refers to the natural gas delivery point on the Enbridge Inc. system at Chetwynd, British Columbia; reference price used in the preparation of British Columbia natural gas reserves.

     • "Henry Hub" refers to a distribution hub on the natural gas pipeline system in Erath, Louisiana and is the pricing point for natural gas futures on the New York Mercantile Exchange.

2. Effective April 1, 2021, the COGE Handbook includes price forecast guidelines for the preparation of commodity price forecasts for use in reserve evaluations. For year-end 2025, the methodology used by Sproule ERCE, GLJ and McDaniel for determining their price forecasts is consistent with the COGE Handbook guidelines.

3. The forecast prices and costs assume the continuance of current laws and regulations, and any increases in wellhead selling prices also take inflation into account. Sales prices are based on reference prices as detailed above and adjusted for quality and transportation on an individual property basis.

4. The Company's 2025 average pricing, net of blending costs and excluding risk management activities, was $87.45/bbl for light and medium crude oil, $73.74/bbl for primary heavy crude oil, $75.07/bbl for Pelican Lake heavy crude oil, $72.42/bbl for thermal bitumen, $53.16/bbl for mining bitumen, $87.10/bbl for SCO, $54.58/bbl for NGLs, and $2.51/Mcf for natural gas.

5. Production and capital costs are escalated at the 3-consultant-average cost inflation rate of 0% per year for 2026 and 2% per year for 2027 and beyond for all products.

6. The 3-consultant-average foreign exchange rate used in the 2025 evaluation was 0.7277 US$/C$ for 2026, 0.7367 US$/C$ for 2027 and 0.7400 US$/C$ for 2028 and beyond.

ADDITIONAL INFORMATION RELATING TO RESERVES DATA Undeveloped Reserves

Undeveloped reserves are reserves expected to be recovered from known accumulations and require significant expenditure to develop and make capable of production. Undeveloped reserves additions result from one or more of the following: acquisitions, infill and extension drilling, or improved recovery in the year when the events first occurred. Proved and probable undeveloped reserves were estimated by the IQRE in accordance with the procedures and standards contained in the COGE Handbook.

Proved Undeveloped

Light and Medium Crude Oil	Primary Heavy Crude Oil	Pelican Lake Heavy Crude Oil	Thermal Bitumen	Mining Bitumen	Synthetic Crude Oil	Natural Gas	Natural Gas Liquids	Barrels of Oil Equivalent
Year (MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(Bcf)	(MMbbl)	(MMBOE)
2023 First Attributed 26	24	-	68	-	35	2,063	82	579
Total 100	80	55	2,596	-	83	10,045	398	4,986
2024 First Attributed 32	22	-	56	-	-	1,982	166	607
Total 129	88	53	2,603	-	96	11,625	533	5,440
2025 First Attributed 47	22	-	82	-	-	905	96	398
Total 160	92	55	2,603	14	91	11,873	575	5,568

Probable Undeveloped

Light and Medium Crude Oil	Primary Heavy Crude Oil	Pelican Lake Heavy Crude Oil	Thermal Bitumen	Mining Bitumen	Synthetic Crude Oil	Natural Gas	Natural Gas Liquids	Barrels of Oil Equivalent
Year (MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(MMbbl)	(Bcf)	(MMbbl)	(MMBOE)
2023 First Attributed 13	15	-	30	-	18	1,076	43	299
Total 48	64	27	1,635	-	18	7,717	257	3,335
2024 First Attributed 14	12	-	18	-	-	1,213	98	343
Total 58	65	28	1,630	-	18	8,569	340	3,567
2025 First Attributed 26	15	1	22	-	-	283	35	145
Total 75	69	30	1,620	-	18	8,021	320	3,469

The assignment of some proved undeveloped and probable undeveloped reserves beyond 2 years is based on the Company's capital development plan to optimize operations and align capital investments with estimated future net revenue. The extended development timing has no consequential impact on the confidence level associated with the reserves estimate in each category. The IQRE reserves evaluation report documents the evaluation, assignment and justification for undeveloped reserves beyond the NI 51-101 development timing guidelines. The Company's justifications for reserves development timing beyond 2 years are summarized by product type below:

1. Light and Medium Crude Oil and Primary Heavy Crude Oil undeveloped reserves are located throughout the Company's core areas in western Canada and Offshore Africa. Development timing is justified to accommodate the following:

   • capital projects with facility constraints and development plans designed to optimize the operation and deliver production for the life of the facilities;

   • resource plays with extensive ongoing development;

   • EOR or waterflood projects with ongoing, extensive development opportunity;

   • strict ESG or regulatory development restrictions limit the development drilling that would otherwise proceed at a quicker pace; and

   • offshore projects with long lead times and facility constraints.

2. Pelican Lake Heavy Crude Oil is produced at a large heavy crude oil polymer EOR flood project with chemical and facility constraints. The development plan is designed to optimize the purchase and use of chemicals and deliver production for the life of the facilities.

3. Thermal Bitumen development plans are designed to optimize the operation and deliver production for the life of the facilities over the next fifty years.

4. Mining Bitumen and Synthetic Crude Oil reserves are associated with two large oil sands mining and upgrading projects with long lead times and facility constraints. The development plans are designed to optimize the operation and deliver production for the life of the facilities.

5. Natural Gas undeveloped reserves are located throughout the Company's core areas in western Canada. Development timing is justified to accommodate the following:

   • capital projects with facility constraints and development plans designed to optimize the operation and deliver production for the life of the facilities;

   • resource plays with extensive ongoing development; and

   • strict ESG or regulatory development restrictions limit the development drilling that would otherwise proceed at a quicker pace.

Significant Factors or Uncertainties Affecting Reserves Data

The development plan for the Company's undeveloped reserves is based on forecast price and cost assumptions. Projects may be advanced or delayed based on actual prices that occur.

The evaluation of reserves is a process that can be significantly affected by a number of internal and external factors. Revisions are often necessary resulting in changes in technical data acquired, historical performance, fluctuations in production costs, development costs and product pricing, economic conditions, changes in royalty regimes and environmental regulations, and future technology improvements. See "Uncertainty of Reserves Estimates" in the "Risk Factors" section of this AIF for further information.

Future Development Costs

The following table summarizes the undiscounted future development costs using the 3-consultant-average inflation and foreign exchange rates as of December 31, 2025. Future development costs exclude all Abandonment, Decommissioning and Reclamation ("ADR") costs. ADR costs are included in the calculation of the future net revenue and consist of both the Company's total North America and Offshore Africa Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as of December 31, 2025 and forecast estimates of ADR costs attributable to future development activity.

Future Development Costs (Undiscounted)

($ millions)	2026	2027	2028	2029	2030	Thereafter	Total	Total Discounted at 10%
Total Proved
North America	4,580	5,250	5,371	5,915	5,432	78,883	105,432	40,346
Offshore Africa	400	50	22	17	24	130	643	532
Total Company	4,980	5,300	5,392	5,932	5,457	79,014	106,074	40,878
Total Proved plus
Probable
North America	4,741	5,503	5,646	6,247	5,746	101,318	129,200	45,531
Offshore Africa	453	59	22	17	24	130	705	590
Total Company	5,194	5,562	5,667	6,264	5,770	101,448	129,906	46,122

Management believes that internally generated cash flows, existing credit facilities and access to debt capital markets are sufficient to fund future development costs. The Company does not anticipate the costs of funding would make the development of any property uneconomic.

Other Oil and Gas Information DAILY PRODUCTION

Set forth below is a summary of the production, before royalties, from crude oil, natural gas and NGLs properties for the fiscal years ended December 31, 2025 and 2024.

	2025 Average Daily Production Rates		2024 Average Daily Production Rates
Region	Crude Oil & NGLs (bbl)	Natural Gas (MMcf)	Crude Oil & NGLs (bbl)	Natural Gas (MMcf)
North America
Northeast British Columbia	22,769	958	23,170	882
Northwest Alberta	108,544	1,151	69,651	903
Northern Plains	412,134	165	401,549	168
Southern Plains	22,786	262	11,401	180
Southeast Saskatchewan	3,168	2	3,517	3
Oil Sands Mining & Upgrading	565,102	-	472,245	-
North America Total	1,134,503	2,538	981,533	2,136
International
North Sea UK Sector	8,468	3	11,536	2
Offshore Africa	3,204	6	12,534	9
International Total	11,672	9	24,070	11
Company Total	1,146,175	2,547	1,005,603	2,147

Northeast British Columbia

The northeast British Columbia region holds a significant portion of the Montney formation and provides exploration and development opportunities in combination with significant controlled infrastructure. The exploration strategy focuses on comprehensive evaluation through two dimensional seismic, three dimensional seismic and targeting economic prospects close to existing infrastructure.

This region includes the Septimus, Umbach/Nig and Townsend Montney natural gas assets with owned natural gas processing capacity as well as dedicated third party natural gas processing capacity.

The southern portion of this region encompasses the Company's BC Foothills assets where natural gas is produced from the deep Mississippian and Triassic aged reservoirs in this highly structural area.