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United States
Securities and Exchange Commission
Washington, D.C. 20549
FORM 40-F
[ ] Registration Statement pursuant to section 12 of the Securities Exchange Act of 1934
[ X ] Annual report pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2023 | Commission File Number: 001-12138

CANADIAN NATURAL RESOURCES LIMITED (Exact name of Registrant as specified in its charter)
ALBERTA, CANADA (Province or other jurisdiction of incorporation or organization)
1311 (Primary Standard Industrial Classification Code Numbers)
Not Applicable (I.R.S. Employer Identification Number (if applicable))
2100, 855-2nd Street S.W., Calgary, Alberta, Canada, T2P 4J8 Telephone: (403) 517-7345 (Address and telephone number of Registrant’s principal executive offices)
CT Corporation System, 28 Liberty Street, New York, New York 10005 (212) 894-8940 (Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of Each Class: | Trading Symbol(s): | Name of each exchange on which registered:
Common Shares, no par value | CNQ | New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
For annual reports, indicate by check mark the information filed with this Form:

[ X ] Annual information form | [ X ] Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
1,072,408,000 Common Shares outstanding as of December 31, 2023
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

1 | Canadian Natural Resources Limited 2023 40-F

Yes [X] | No [ ]

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes [X] | No [ ]

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging Growth Company | [ ___ ]

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
†

| [ ___ ]

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Yes [X] | No [ ]

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements

| [ ___ ]

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recover period pursuant to §240.10D-1(b).

| [ ___ ]

† The term new or revised financial accounting standard refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
This Annual Report on Form 40-F shall be incorporated by reference into, or as an exhibit to, as applicable, the Registrant’s Registration Statement on Form F-10 (File Nos. 333-258127 and 333-273475) under the Securities Act of 1933, as amended.

Canadian Natural Resources Limited 2023 40-F | 2

PRINCIPAL DOCUMENTS
The following documents have been filed as part of this Annual Report on Form 40-F, starting on the following page:

| A. | Annual Information Form

Annual Information Form of Canadian Natural Resources Limited (“Canadian Natural”) for the year ended December 31, 202 3.

| B. | Audited Annual Financial Statements

Canadian Natural’s audited consolidated financial statements for the years ended December 31, 202 3 and 202 2 including the report of independent registered public accounting firm (PCAOB ID 271) with respect thereto.

| C. | Management’s Discussion and Analysis

Canadian Natural’s Management’s Discussion and Analysis for the year ended December 31, 202 3.
The following document is filed as an exhibit to this Annual Report on Form 40-F and is incorporated by reference herein:

| A. | Supplementary Oil & Gas Information (Unaudited)

For Canadian Natural’s Supplementary Oil & Gas Information (Unaudited) for the year ended December 31, 202 3, see Exhibit 99.1 to this Annual Report on Form 40-F.

3 | Canadian Natural Resources Limited 2023 40-F

CANADIAN NATURAL RESOURCES LIMITED

ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2023
March 20, 2024

Principal Documents Exhibits

Annual Information Form

Table of Contents

Definitions and Abbreviations | 2
Advisory | 4
Corporate Structure | 6
General Development of the Business | 7
Description of the Business | 9
A. Environmental Matters | 10
B. Regulatory Matters | 12
C. Competitive Factors | 14
D. Risk Factors | 14
Form 51-101F1 Statement of Reserves Data and Other Information | 21
Selected Financial Information | 49
Dividend History | 50
Description of Capital Structure | 50
Market for Securities | 52
Directors and Executive Officers | 53
Legal Proceedings and Regulatory Actions | 57
Interest of Management and Others in Material Transactions | 57
Transfer Agents and Registrar | 57
Material Contracts | 57
Interests of Experts | 57
Audit Committee Information | 57
Additional Information | 59
Schedule “A” Form 51-101F2 Report On Reserves Data by Independent Qualified Reserves Evaluator or Auditor | 60
Schedule “B” Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure | 63
Schedule “C” Charter of the Audit Committee of the Board of Directors | 65

1 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
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 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
CO 2 | carbon dioxide
CO 2 e | carbon dioxide equivalents
crude oil | includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, synthetic crude oil and bitumen (thermal 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
IASB | International Accounting Standards Board
IFRS | International Financial Reporting Standards
Mbbl | thousand barrels
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

Canadian Natural 2023 Annual Information Form | 2

Principal Documents Exhibits

MMBtu | million British thermal units
MMcf | million cubic feet
MMcf/d | million cubic feet per day
MM$ | million Canadian dollars
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
net zero | refers to emissions (Scope 1 and Scope 2) from oil sands operations
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.
Pathways Alliance or Pathways | Formerly known as the "Pathways to Net Zero Alliance", is an alliance of oil sands producers, working collectively with federal and certain provincial governments, to achieve net zero GHG emissions from oil sands operations by 2050. All net-zero references herein apply to emissions from oil sands operations (defined as scope 1 and scope 2 emissions).
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
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
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

3 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
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 expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital 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, NGLs or SCO 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 "2024 Activity" section of this AIF with respect to budgeted capital expenditures for 2024, the impact of the Pathways Alliance initiative and activities including any projects pursued in connection therewith such as the carbon trunk line and storage hub, government support for Pathways and the ability to achieve net zero emissions from oil production; targeted International decommissioning activities and the timing thereof, and any targeted payouts pursuant to the Company's free cash flow allocation policy, 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 a ctions of OPEC+, the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, increased inflation and decreased economic activity resulting from a global recession, the impact of transmissible diseases including variants of the COVID-19 coronavirus) 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; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the Company's ability to prevent and recover from 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 Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; the Company's and its subsidiaries' ability to complete capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected disruptions or delays in the 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 and its subsidiaries’ 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; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset

Canadian Natural 2023 Annual Information Form | 4

Principal Documents Exhibits
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 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 and local laws and regulations such as restrictions on production or emissions, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. 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 “Risks 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, 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 comparative Consolidated Financial Statements and the Company’s MD&A for the most recently completed fiscal year ended December 31, 2023, are herein incorporated by reference, and certain information included in this AIF, have been prepared in accordance with IFRS, as issued by the IASB.
For the year ended December 31, 2023, the Company retained Independent Qualified Reserves Evaluators (“IQRE”), Sproule Associates Limited and Sproule International Limited (together, “Sproule”) 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, 2023 and a preparation date of February 5, 2024. Spr oule evaluated and reviewed the North America and International light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), natural gas and NGLs reserves. GLJ evaluated the Oil Sands Mining and Upgrading 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 2023 A nnual Report, which is incorporated herein by reference.
SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES
This AIF includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings from operations; adjusted funds flow; netback; and net capital expenditures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP financial measures, as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). Non-GAAP measures are used by the Company to evaluate its financial performance, financial position or cash flow. Descriptions of the Company's non-GAAP measures "adjusted net earnings from operations," “adjusted funds flow,” "netback," and “net capital expenditures,” included in this AIF, are provided in the “Non-GAAP and Other Financial Measures” section of the Company’s annual MD&A for the year ended December 31, 2023, dated February 28, 2024. "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.

5 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
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.
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:

January 1, 2014 - Barrick Energy Inc.
January 1, 2015 - EOG Resources Canada Inc.
January 1, 2019 - Laricina Energy Ltd.
October 1, 2020 - CNRL Upgrading Limited
January 1, 2021 - Painted Pony Energy Ltd.
January 1, 2022 - Storm Resources Ltd.; Storm Gas Resource Corp.; CNR Montney Ltd.
January 1, 2023 - Horizon Construction Management Ltd.

The head, principal and registered office of the Company is located in Calgary, Alberta, Canada at 2100, 855 - 2nd Street S.W., T2P 4J8.
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
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. In 2023, Canadian Natural wound up its subsidiary, CNR (Echo) Resources Inc., and two of its operating partnerships, being Canadian Natural Resources and Canadian Natural Resources Northern Alberta Partnership.
The consolidated financial statements of Canadian Natural include the accoun ts 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.

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Principal Documents Exhibits
General Development of the Business
2021
The rollout of the COVID-19 vaccine, together with the continuation of agreements by OPEC+ to maintain the majority of production cuts had an overall positive impact in 2021 on global demand and benchmark pricing for crude oil and the Company's products.
In January 2021, the presidential permit granted in 2019 on the Keystone XL Pipeline was revoked following the inauguration of the newly elected US President. The Company accrued a charge relating to the Keystone XL pipeline project of $143 million in the fourth quarter of 2020.
In 2021, the Company made a number of adjustments to its debt financing plan. This included the repayment and cancellation of the remaining balance on the $3,250 million committed term facility put in place to finance the 2019 acquisition of substantially all of the assets of Devon Canada Corporation due in June 2022. In the third quarter, the Company repaid the US$500 million 3.45% notes originally due November 15, 2021. The Company also repaid $1,500 million on its $2,650 million term credit facility originally due February 2023, which reduced the facility balance to $1,150 million as at November 3, 2021. In the fourth quarter, the Company repaid the outstanding notional balance under its $1,000 million credit facility, which credit facility was not cancelled upon repayment and remained available to be drawn until March 31, 2022. In the fourth quarter, the Company also extended both of its $2,425 million revolving syndicated credit facilities originally due June 2022 and June 2023, to June 2024 and June 2025 respectively and increased each facility by $70 million to $2,495 million. In accordance with the terms of the extensions, and by mutual agreement, $70 million on each of the original revolving credit facilities was not extended or expired on the original maturity dates of June 2022 and June 2023, respectively. Additionally, in the third quarter, the Company filed base shelf prospectuses that allow for the offer of up to $3,000 million of medium term notes in Canada and US$3,000 million of debt securities in the United States, which expired in August 2023, replacing the Company's previous base shelf prospectuses which expired in August 2021.
On June 9, 2021, the Company, together with Cenovus Energy, Imperial Oil, MEG Energy and Suncor Energy, announced the Oil Sands Pathways to Net Zero initiative (now referred to as the "Pathways Alliance"), a unique alliance working collectively with the federal and Alberta governments to achieve net zero GHG emissions from oil sands operations by 2050. This groundbreaking industry and government collaboration is intended to support achievement of Canada's climate goals through the parallel development and deployment of next generation emissions reduction technology, infrastructure and operations projects designed to improve efficiency and reduce GHG emissions while balancing sustainable economic development and positioning Canadian oil and gas production to be the ESG-leading barrel to meet global energy demand.
In 2021, the Company completed the acquisition of all the issued and outstanding common shares of Storm Resources Limited ("Storm") for total cash consideration of approximately $771 million. At closing, the acquisition also included the assumption of long-term debt of approximately $183 million. Storm and CNR Montney Ltd. were amalgamated with the Company on January 1, 2022. Storm was involved in the exploration and development of natural gas and NGLs in the Montney region of British Columbia.
In 2021, the Company also completed a number of other opportunistic acquisitions. Two acquisitions consisted of natural gas assets located in the Montney region of British Columbia, with aggregate production of approximately 11,100 BOE/d. A third acquisition consisted of a net carried interest on an existing oil sands lease held by the Company. Total cash consideration paid for these acquisitions was approximately $450 million.
2022
In January 2022, the Company consolidated its development opportunities at Jackfish and Kirby by acquiring the remaining 50% interest in the undeveloped Pike lands located adjacent to Jackfish.
The Company made a number of adjustments to its debt financing plan in 2022. This included the repayment and cancellation of the $1,150 million term credit facility originally due February 2023. The Company also amended the $1,000 million credit facility by extending the maturity date to February 2024 and making it a $500 million revolving credit facility. In February, the Company repaid at maturity $1,000 million of 3.31% medium-term notes, and, in December, the Company repaid US$1,000 million of 2.95% notes originally due in January 2023. Throughout 2022, the Company also repurchased $498 million of its medium-term notes with interest rates ranging from 1.45%-3.55%, originally due between 2023 and 2028.
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 is targeted to commence in late 2024, and is anticipated to be completed in 2027. Upon completion, the Pike 1 project is targeted to add approximately 25,000 bbl/d of 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, which is targeted to commence in 2024 and is targeted to be mechanically complete in the third quarter of 2027. This project aims to reduce GHG emissions, equivalent to approximately 6% of Horizon's total Scope 1 emissions, while concurrently providing incremental production increases and anticipated lower reclamation costs over the life of the Horizon project.

7 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
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 expire 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.

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Principal Documents Exhibits
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 in a sustainable and responsible way, maintaining a commitment to environmental stewardship and safety excellence.
The Company has a full complement of management, technical and support staff to pursue these objectives. As of December 31, 2023, the Company had the following full time equivalent permanent employees:

North America, Exploration and Production | 5,108
North America, Oil Sands Mining and Upgrading | 4,867
North Sea and Offshore Africa | 297
Total Company | 10,272

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, natural gas, light and medium crude oil and NGLs, bitumen (thermal oil), 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 34% of 2023 annual production. Natural gas, primarily produced in Alberta, British Columbia and Saskatchewan, accounted for 27% of 2023 annual production. Light and medium crude oil and NGLs represented 10% of 2023 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. Also produced from Alberta and Saskatchewan were bitumen (thermal oil), which accounted for 20% of 2023 annual production, primary heavy crude oil which accounted for 6% of 2023 annual production, and Pelican Lake heavy crude oil, which accounted for 3% of 2023 annual production. 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 bitumen operations. Midstream assets also include a 50% equity interest in the North West Redwater Partnership.
As part of the Company's ongoing focus on technology and innovation and the reduction of its environmental footprint, the Company has previously implemented and continues to undertake projects such as: carbon capture, sequestration, storage and utilization projects, as well as methane emissions reduction programs at the Company's facilities. In addition, the Company installs equipment powered by renewable energy sources, where appropriate.
The Company has 20 year transportation agreements to ship 94,000 bbl/d of crude oil on the Trans Mountain Pipeline Expansion ("TMX") that will provide waterborne access to international markets. Construction of the TMX was approximately 98% complete as of January 12, 2024. Trans Mountain Corporation has announced that it is working towards an anticipated in service date in the second quarter of 2024.

9 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
A. 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, review the operations of the Company’s world-wide interests, 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 authoriti es in each of the regions where the Company operates. The Company’s associated environmental risk management strategy incorporates working constructively with legislators and regulators to ensure that any new or revised policies, legislation or regulations properly reflect a balanced approach to sustainable development. Specific measures undertaken in response to existing or new legislation include a focus on the Company’s energy efficiency, air emissions management, water management and land management to minimize disturbance impacts. 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 focus on minimizing the environmental impact of operations while meeting: regulatory requirements; regional management frameworks for biodiversity, air quality and emissions, and ground and surface water; industry operating standards and guidelines; and internal corporate standards. Training and due diligence for operators and contractors is key to the effectiveness of the Company's environmental management programs and the prevention of incidents to protect the environment.
Canada
The Company continues to invest in people, facilities and infrastructure, and 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 to reduce its environmental footprint including: environmental planning to assess impacts and implement avoidance and mitigation programs in order to maintain biodiversity for terrestrial and aquatic systems and high value ecosystems; continued evaluation of new technologies to reduce environmental impacts; mitigation of the Company's climate change impacts through implementation of various emissions reduction programs and carbon capture projects (including CO 2 injection for EOR, CO 2 sequestration in tailings and the Quest Carbon Capture and Storage Facility); a methane emissions reduction program, including solution gas conservation to reduce methane venting and an equipment retrofit program to reduce emissions from pneumatic equipment; and optimization of efficiencies at the Company's facilities.
In 2023, the Company, as a founding member and contributor to the Pathways Alliance, continued to progress work in support of achieving the goal of net zero GHG emissions from oil sands operations by 2050 to help Canada achieve its climate goals, including its Paris Agreement commitment.
The Company continues to monitor and evaluate government programs intended to advance industry investments in GHG decarbonization projects. On November 30, 2023, the federal government tabled Bill C-59 in the House of Commons to provide an investment tax credit ("ITC") for capital invested in eligible carbon capture, utilization and storage ("CCUS") projects. If passed, this legislation would offer 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 rates being halved from 2031 to 2040 and fully phased out after 2040. In November 2023, the government of Alberta announced it would provide a 12% tax credit on eligible capital costs associated with building new CCUS projects.
As a result of advancements in Pathways Alliance initiatives and ongoing progress in the Company's GHG reduction projects, the Company announced a new corporate GHG emissions reduction target in November 2022. The target is to reduce total corporate absolute Scope 1 and Scope 2 GHG emissions by 40% by 2035 from a 2020 baseline. This target is in addition to the Company's North American E&P methane emissions reduction target of 50% by 2030 from a 2016 baseline and an aspirational goal of net zero emissions in its oil sands mining and thermal operations.
The Company has an integrated GHG emissions reduction strategy which includes: integrating emissions reduction into project planning and operations; leveraging technology to create value and enhance performance; investing in research and development including collaboration with industry, entrepreneurs, academia and governments; focusing on continuous improvement to drive long-term emissions reduction; leading in carbon capture, sequestration and storage; engaging in policy

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Principal Documents Exhibits
and regulatory development (including trading capacity and offsetting emissions); and reviewing and developing new business opportunities and trends that present further opportunities to reduce the Company's environmental footprint. The Company participates in both federal and provincially-regulated climate and GHG emissions reporting programs and continues to quantify annual GHG emissions for internal reporting purposes to drive continuous improvement and reduction in absolute GHG emissions and intensity. The Company published its 2022 Stewardship Report to Stakeholders in the third quarter of 2023. This report included third party independent "reasonable assurance" on its 2022 Scope 1 and Scope 2 emissions, including methane emissions, and "limited assurance" on its Scope 3 emissions. For 2023, the Company has also engaged an independent third party to provide "reasonable assurance" on its 2023 Scope 1 and Scope 2 emissions, including methane emissions, and "limited assurance" on its Scope 3 emissions.
The Company, through industry associations, is working with Canadian legislators and regulators as they develop and implement new GHG emissions laws and regulations to support emissions reductions and properly reflect a balanced approach to sustainable development.
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. Internally, the Company continues to enhance its integrated emissions reduction strategy to ensure that it is able to comply with existing and future emissions reduction requirements for GHGs and air pollutants (such as sulphur dioxide and oxides of nitrogen). The Company continues to participate in air quality monitoring through regional organizations. Data collected through regional air shed monitoring is used by government to develop management programs and frameworks.
The Company continues to implement flaring, venting and solution gas conservation programs, which influence and direct its future plans for new projects and facilities. In 2023, the Company completed 207 solution gas conservation projects in its primary heavy crude oil operations, which resulted in a reduction of approximately 1.07 million tonnes/year of CO 2 e. From 2019 to 2023, the Company spent over $23.6 million in its primary heavy crude oil and in situ oil sands operations to conserve the equivalent of over 9.1 million tonnes of CO 2 e. As part of the Company's initiatives to optimize and improve fuel gas efficiency, the Company monitors compressor fleet performance, and has ongoing methane reduction programs for pneumatic devices. From 2018 to 2022, the Company completed a pneumatic instrument program with over 8,000 pneumatic retrofits and removals resulting in a cumulative CO 2 e reduction from its operations of approximately 815,000 tonnes/year. In 2022 and 2023, the Company installed 1,399 solar powered chemical injection pumps as part of an ongoing multi-year pneumatic chemical injection pump replacement program, which resulted in approximately 190,000 tonnes/year CO 2 e reduction once completed. Oil Sands Mining has incorporated advancements in technology to further reduce GHG emissions through maximizing heat integration, the use of cogeneration to meet steam and electricity demands and the design of the hydrogen production facility that enables CO 2 capture of up to 400,000 tonnes/year for injection of CO 2 in oil sands tailings, and the recovery of hydrocarbon liquids from refinery fuel gas. Additionally, at the Company's non-operated Quest Carbon Capture and Storage Facility, approximately 1 million tonnes/year of CO 2 is captured and permanently sequestered in geological storage. Since 2015, approximately 9 million tonnes of CO 2 has been captured and safely stored at Quest.
The Company has water programs to improve the efficiency of use and recycle rates as well as reduce fresh water use, including new targets related to fresh river water use intensity in its oil sands mining operations and fresh water use intensity in its thermal in situ operations, both of which were announced in 2021. As part of its drilling practices, the Company has also adopted the Hydraulic Fracturing Operating Practices that were developed by the Canadian Association of Petroleum Producers in support of a responsible approach to hydraulic fracturing and water management.
The Company has effective programs for well abandonment and decommissioning that allows for the progressive reclamation of large contiguous areas of land and provides the foundation for the enhancement of biodiversity and functional wildlife habitats. The Company continued its environmental liability reduction program in 2023 with the abandonment of 2,068 inactive wells, and has initiated reclamation at many of these sites with the eventual goal of reclamation certification. In 2023, the Company received 1,311 reclamation certificates representing 2,358 hectares of land. From 2019 to 2023, the Company abandoned 11,368 inactive wells and received 4,712 reclamation certificates representing 10,014 hectares of reclaimed land. Further, decommissioning of inactive facilities and cleanup of active facilities was conducted to address environmental liabilities at operating sites. Additionally, the Company has comprehensive programs in place for: tailings management in its oil sands mining operations to minimize fine tailings and promote reclamation; monitoring programs to assess changes to biodiversity, wildlife and fisheries in order to manage construction and operational effects and to assess reclamation success; participation and support for the Oil Sands Monitoring Program of regionally important resources; groundwater monitoring for all thermal in situ and mine operations; an active spill prevention and management program; and an internal environmental management system for conformance audit and inspection programs of operating facilities.
International
In 2023, the Company's subsea decommissioning planning activities continued for the Banff and Kyle fields with the removal of the subsea pipelines and infrastructure targeted for 202 4. Planning for the decommissioning and abandonment of the Ninian, Columba, Lyell and Strathspey fields is underway with Ninian well plug and abandonment having commenced in the fourth quarter of 2023. In addition, planning commenced for the decommissioning of the Ninian Hub Area including surveys and studies required for development of the decommissioning program(s), and the initiation of regulatory and key stakeholder engagement.

11 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
B. REGULATORY MATTERS
The Company’s business is subject to regulations generally established through government legislation and governmental agencies. A summary of certain key regulatory regimes impacting the Company's operations are summarized in the following paragraphs.
Canada
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 federal or respective provincial governments, which give the holder the right to explore for and produce bitumen, crude oil, and natural gas. 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 portions of the 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 and natural gas as well as the removal of natural gas and NGLs from their respective province. 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.
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. Wells drilled between July 13, 2016 and December 31, 2016 could elect to opt-in to the MRF if certain criteria were met. Under the MRF, conventional royalty rates will range from 5% to 36% for natural gas and NGLs and 5% to 40% for crude oil.
The Company was subject to federal and provincial income taxes in Canada at a combined rate of approximately 23.3% in 2023. The government of Alberta decreased the provincial corporate income tax rate from 12% to 10% over the period July 1, 2019 to January 1, 2020. The current provincial income tax rate of 8% took effect on July 1, 2020.
On May 19, 2022, the Government of British Columbia announced a new royalty framework, which comes into effect on September 1, 2024. 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.
In 2021, the Alberta Energy Regulator (“AER”) announced a new Liability Management Framework (the "Framework") as part of its life-cycle management of oil and gas wells, facilities and pipelines, which imposes annual mandatory spending targets for companies for the closure of inactive wells and related infrastructure. Under the Framework, the AER assigns licensees a mandatory annual spend target for their abandonment and reclamation activities, which is determined based on a licencee's proportionate share of the provincial inventory of inactive wells and related infrastructure among other factors. Mandatory spend targets became effective January 1, 2022 and were increased for the 2023 performance year. In 2022, the government of Saskatchewan also introduced the Inactive Liability Reduction Program and the government of British Columbia updated its Dormancy and Shutdown Regulations, which provide mandatory targets for decommissioning and restoring inactive wells and facilities in those provinces.
▪Federal Carbon Compliance Costs
Governments in jurisdictions where the Company operates have developed or are developing GHG regulations as part of their national and international climate change commitments. The Company uses existing GHG regulations to determine the impact of compliance costs on current and future projects. The Company monitors the development of GHG regulations on an ongoing basis in the jurisdictions in which it operates to assess the impact of future regulatory developments on the Company's operations and planned projects. In Canada, the federal government has ratified the Paris Agreement, with a commitment to reduce GHG emissions by 40-45% from 2005 levels by 2030. The Canadian government has also committed to cap and cut emissions from the oil and gas sector and in December 2023, announced a regulatory framework

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Principal Documents Exhibits
for a national cap and trade system with plans to publish draft regulations by mid-2024. The draft framework currently proposes to cap 2030 emissions at 35-38% below 2019 levels (as estimated by Environment and Climate Change Canada) while providing some compliance flexibility to emit up to 20-23% below the 2019 threshold. I n December 2020, the federal government announced its intention to increase the carbon price to $170/tonne by 2030 in annual increments of $15/tonne after 2022. The federal government is also developing a comprehensive management system for air pollutants and has released regulations pertaining to certain boilers, heaters and compressor engines operated by the Company. Additionally, in 2022, the federal government released the Clean Fuel Regulations that became effective on July 1, 2023 which apply to producers or importers of gasoline and diesel fuels and require reductions in the carbon intensity associated with gasoline and diesel fuels produced and supplied in Canada.
▪Provincial Carbon Compliance Cost
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. Such future reviews may affect the carbon price and/or the stringency of provincial systems.
Effective January 1, 2020, Alberta replaced the GHG regulation (the Carbon Competitiveness Incentive Regulation) with the Technology Innovation and Emissions Reduction Regulation ("TIER"). TIER applies to all of the Company’s assets in Alberta (as an alternative to the federal fuel charge). In December 2022, the Alberta government published changes to TIER that took effect January 1, 2023, that reduce the amount of emissions allocations for regulated facilities. Emissions coverage within TIER was also expanded to include flaring from all TIER regulated facilities. The carbon price in Alberta for emissions above the TIER regulated limits was $65/tonne in 2023 and increases annually in $15/tonne increments to $170/tonne in 2030, which aligns with the federal carbon pricing schedule. The non-operated Scotford Upgrader and North West Redwater bitumen upgrader and refinery are also subject to compliance under TIER.
In British Columbia, the carbon tax on fuel consumed and gas flared and vented in the province is currently being assessed at $65/tonne of CO 2 e and is expected to continue to increase by $15/tonne CO 2 e annually until reaching $170/tonne of CO 2 e in 2030 as stated in the 2023 provincial budget, which aligns with the federal carbon pricing schedule. Additionally, the government of British Columbia announced in its 2023 budget that it would replace its carbon tax for large industrial emitters with an output based pricing system that will take effect on April 1, 2024. In March 2023, British Columbia announced its intention to implement an emissions cap in place for the oil and gas industry to ensure that the province meets its 2030 emissions reduction target for the sector. This target aims to reduce oil and gas industry emissions by 33-38% below 2007 levels by 2030. The British Columbia government also announced its intention to implement a Net-Zero New Industry policy.
As part of its Prairie Resilience Plan, the Saskatchewan government has a regulation (“The Management and Reduction of Greenhouse Gases (Standards and Compliance) Regulations”) that applies to facilities emitting more than 25 kilotonnes of CO 2 e annually and requires the North Tangleflags in situ heavy crude oil facility and the Senlac in situ heavy crude oil facility to meet reduction targets for GHG emissions effective 2020. This regulation also enables facilities below the threshold to aggregate and opt into the Saskatchewan regulatory system as an alternative to the federal fuel charge. This regulation also adopts the federal carbon pricing schedule to 2030.
In Manitoba, the federal output-based pricing system and carbon pricing schedule applies to facilities with emissions greater than or equal to 50 kilotonnes CO 2 e annually. Facilities with emissions equal to or greater than 10 kilotonnes CO 2 e annually can voluntarily opt-in to the system.
▪Federal and Provincial Methane Emissions Reduction Regulations:
By 2025, the federal government has committed to reduce methane emissions from the oil and gas sector by 40-45% below 2012 levels. The federal government’s methane regulation came into effect on January 1, 2020 and applies nationally unless provinces reach equivalency agreements with the federal government, in which case the federal regulation does not apply. The provinces of British Columbia, Alberta and Saskatchewan have implemented provincial methane regulations, and have reached equivalency agreements with the federal government. Accordingly, the applicable provincial methane regulations govern in the three western provinces whereas the federal methane regulation applies to methane emissions in the province of Manitoba.
In 2022, the federal government announced a framework for expanding methane regulations to achieve at least a 75% reduction below 2012 levels by 2030 with the draft regulatory framework released in November 2022 and amendments published in December 2023. Feedback on the draft regulations will continue into 2024.
United Kingdom
Under existing law, the UK government has broad authority to regulate the petroleum industry, including exploration, development, conservation and rates of production.
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

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taxation years. The UK government introduced an Energy Profits Levy in May 2022 at a rate of 25%. This was subsequently increased to 35% in November 2022 and will apply until March 31, 2028. There is an investment allowance on qualifying capital expenditure of 29%. As a result of these changes, the tax rate applicable to taxable income from oil and gas activities is 75% 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.
GHG regulations have been in effect in the UK since 2005. In Phase 1 (2005 – 2007) of the UK National Allocation Plan, the Company operated below its CO 2 allocation. In Phase 2 (2008 – 2012), the Company’s CO 2 allocation was decreased below the Company’s operations emissions. In Phase 3 (2013 – 2020) the Company’s CO 2 allocation was further reduced. Following the UK's withdrawal from the European Union ("EU") on January 31, 2020, a new UK Emissions Trading Scheme ("ETS") was launched on January 1, 2021. The new scheme is aligned with the EU ETS rules and applies to energy intensive industries, the power generation sector and aviation. The Company continues to focus on implementing CO 2 emissions reduction opportunities at its facilities and on trading mechanisms to ensure compliance with requirements now in effect.
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.
In 2023, the CDI government amended its local content regulations, increasing the requirements to use local personnel, businesses and services. The Company is in discussions with the applicable authorities and with its contractors with regard to compliance with these enhanced regulations.
C. 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 and NGLs, and electricity, 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.
D. 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. 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. the Russian invasion of Ukraine, and conflicts in the Middle East), the foreign supply of crude oil, 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

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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, and prices of alternate sources of energy. 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.
Approximatel y 29% o f the Company’s 2023 production on a BOE basis was primary heavy crude oil, Pelican Lake heavy crude oil, and bitumen (thermal oil). The market prices for these products currently 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. 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.
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 significant changes to certain existing projects may require the submission and approval of environmental impact assessments or permit applications. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties. 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 expected 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 Risk
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. Although the Company believes that such independent external scenario analyses are reasonable, if inaccurate, it may have a material adverse effect on the Company's business, financial condition and results of operations. Since the Company plans and evaluates opportunities partially on the basis of climate-related estimates, 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, societal preferences and reputational risk, and technology development, as described in more detail below.

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▪Future Regulatory Changes / Compliance Costs / Reduction Targets
The additional requirements of enacted or proposed GHG regulations on the Company’s operations may increase capital expenditures and production expenses, including those related to the Company’s existing and planned oil sands projects. This may have an adverse effect on the Company’s financial condition. Accordingly, existing and proposed climate change policies and regulations are considered when making decisions to advance the Company’s business strategy. The Company tracks the development of policies and regulations at the international, national, federal and provincial level. In December 2020, the federal government announced its intention to surpass Canada’s previously stated reduction target under the Paris Agreement, to increase the carbon price to $170/tonne by 2030, and to establish methane reduction targets for 2030 and 2035. In addition, the Clean Fuel Regulations came into force in July 2023. Aspects of the Clean Fuel Regulations will increase the cost of liquid fuels consumed in the Company’s operations while also providing a potential mechanism to generate offset credits. In 2023, the federal government released draft Clean Electricity Regulations, which may increase the cost of electricity generated or purchased by the Company, if adopted as proposed.
In addition to the Pathways initiative, the Company continues to pursue other GHG emissions reduction initiatives in its operations including: solution gas conservation, compressor optimization to improve fuel gas efficiency, reductions/retrofits in pneumatic devices, CO 2 capture and injection in oil sands tailings, CO 2 capture and storage in association with EOR, CO 2 capture and storage at Quest, and technology development through participation in various research and innovation groups.
Various jurisdictions have enacted or are evaluating low carbon fuel standards, which may affect access to market for crude oils with higher emissions intensity. The Canadian government and certain provincial governments have published regulations to reduce methane emissions from the oil and natural gas sector, in support of a joint commitment made by the US and Canadian governments to lower emissions from the sector by 2025. 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.
The Company's ability to achieve government, Pathways 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 proposed Clean Electricity Regulations may impact the demand for natural gas.
▪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. Changes in government policy have the potential to impact the certainty and timelines for the regulatory process on large energy projects, including increased requirements for Indigenous consultation. Some examples include the federal Canadian Net-Zero Emissions Accountability Act, federal legislation implementing the United Nations Declaration on the Rights of Indigenous Peoples Act, and the federal Impact Assessment Act, the Alberta sub-regional plans supporting caribou recovery, the British Columbia Declaration on the Rights of Indigenous Peoples Act (DRIPA), and the Blueberry River First Nations Implementation Agreement, which was negotiated by the government of British Columbia to address issues raised in recent 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).

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▪Access to Markets
The Company may be exposed to greater market risk for its products associated with the shift to a lower carbon emissions future. These risks may include increases in the demand for renewable energy sources, increases in compliance costs that may not be recoverable in the price of the product, which could delay the development of certain assets, and restricted access to markets for higher carbon energy sources, including as a result of the delay, revocation, or conditions imposed on, regulatory approvals for pipeline projects. These risks could result in a competitive disadvantage if producers in other jurisdictions are not subject to similar regulatory burdens.
▪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 the AOSP'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 with improved performance in tailings management for the full life of the mines as well as the proposed tailings treatment technologies. 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. Research and mitigative technologies are in development to reduce fluid tailings and to increase the certainty of achieving the tailings targets for the Horizon and AOSP mines. Through Canada's Oil Sands Innovation Alliance, the innovation arm of Pathways, technology development is jointly undertaken by all oil sands mine operators to accelerate the commercialization of such projects.
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 continues to advance the decommissioning 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, further reducing the mine's environmental risk and liability. The South Expansion Area was fully revegetated and reclaimed in 2023. Muskeg River Mine also obtained the decommissioning authorization for the removal of a sedimentation pond in 2022.
▪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 biodiversity and wildlife that may place limits on crude oil and natural gas development. Management frameworks in the Lower Athabasca oil sands area establish limits and triggers for surface and ground water quality and quantity, and air emissions 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. Regional access management plans may pose limitations on resource development through limits on infrastructure. In December 2023, the federal government announced the intention to introduce the Nature Accountability Bill in 2024 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. In November 2023, the Alberta government announced water conservation plans for 2024 to address potential drought conditions, which plans are being assessed by the Company for potential operational impacts and mitigation strategies.
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 return habitat function by restricting predator access on seismic lines, restoring forests through accelerated reclamation and completing project development planning to minimize caribou disturbance. In addition, mitigation activities such as maternity pens to raise young caribou are being supported by the Company to improve herd populations. The presence of other species at risk such as birds or amphibians requires that operations be managed to avoid or mitigate effects resulting in potential operational inefficiencies and delays.
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, among others, fires, explosions, spills, blow outs or other

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unexpected or dangerous conditions causing personal injury, property damage, environmental damage, 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 may pose 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 (ERPs) 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 manpower 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 manpower, the availability and proximity of materials, pipeline capacity, weather, fires, drought, 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, could affect the Company's ability to access cost-

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effective capital. In addition, changes in credit ratings may affect the ability to, and the associ ated 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 and is subject to credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts. 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 Security
The Company has become increasingly dependent on information technology systems to effectively operate and conduct business. The nature and complexity of information security risks that may negatively impact the Company continue to evolve as cyber criminals develop new schemes to target businesses and perpetrate cyber-related crimes that target the information technology ("IT") and business systems of the Company. A significant interruption or failure of the Company’s IT systems (or the IT systems of key vendors and third parties, including cloud-based systems), control systems, sensitive data or a significant breach of security could have a material adverse effect on the Company’s business, financial condition, reputation and results of operations. Monitoring and management of the Company's cyber security risk program falls under the mandate of the Audit Committee of the Board of Directors, which receives reports on cyber security twice annually or more frequently in elevated threat conditions or when circumstances otherwise warrant.
Notwithstanding the Company’s proactive approach to combating cybersecurity threats, such threats frequently change and require evolving monitoring, detection and response efforts. Examples of such threats include: the installation of ransomware (such as was experienced by the Colonial Pipeline in 2021) and the cyber attack suffered by Suncor Energy Inc. in 2023. These types of attacks may disrupt access to the system, publicize private data and potentially destroy the system should the ransom not be satisfied; social engineering to gain unauthorized access to systems facilitating theft, impersonation, fraud and disruption to operations; and the installation of malware which could facilitate loss of access, data destruction, data exfiltration or complete system failure. Any of these threats could interfere with the operation of, or cause damage to, Company property or result in the loss, disclosure or theft of confidential information related to the Company’s proprietary business activities, the personnel files of its employees and personal information of landowners, vendors, customers and other third parties doing business with the Company.
A successful cyber-crime incident could result in damage to assets and financial losses to the Company, operational disruption, remediation and recovery costs, legal claims or proceedings, regulatory penalties, physical harm to people or the environment and reputational issues with suppliers, customers, stakeholders and business partners who may also be impacted by the scheme. To address these risks, the Company maintains robust cyber security protocols and has adopted and continuously improves an industry standard cyber security framework including expedited security patching, vulnerability scanning of all systems, regular cyber assessment of critical third parties, continuous penetration testing of external systems, annual targeted penetration testing of internal processes and systems, risk based remediation of vulnerabilities, 24 hour managed security monitoring and response, incident response readiness drills, multi-factor authentication and routine education/test programs that train personnel to identify potential threats (i.e. phishing) in addition to the internal accounting and process controls. Data restoration and recovery processes are in place to return the Company's operations to a functional state and to minimize the risk of data loss and the resulting disruption to the business. Although the Company has not suffered any material losses related to a cyber security incident to date, there is no assurance that the Company will not suffer material losses associated with cyber security breaches in the future.
Although the Company has implemented cybersecurity protocols and procedures to address this risk, such protocols and procedures may be insufficient to prevent or mitigate information security risks and the Company could incur significant costs to remedy the effects of a major cyber security disruption. The Company maintains insurance as part of its risk management program but such insurance may not be adequate or sufficient to cover all damages sustained by the Company in connection with a cyber incident, and in certain instances, may not respond at all.
Foreign Investments
The Company’s foreign investments inclu de risks typically associated with investments in developing countries such as uncertain political, economic, legal and tax environments. These risks may includ e, 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 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

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royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses 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 repurchas es after capital requirements an d 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 manpower 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.
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 manpower 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 subsidiari es 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.
For additional details regarding the Company's risks and uncertainties, refer to the Company's MD&A for the year ended December 31, 2023.
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. Additional work is required to assess and understand this risk and to 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.
(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.

Canadian Natural 2023 Annual Information Form | 20

Principal Documents Exhibits
Form 51-101F1 Statement of Reserves Data and Other Information
For the year ended December 31, 2023, the Company retained Independent Qualified Reserves Evaluators (“IQRE”), Sproule Associates Limited and Sproule International Limited (together as “Sproule”) 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, 2023 and a preparation date of February 5, 2024. S proule evaluated and reviewed the North America and International light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), natural gas and NGLs reserves. GLJ evaluated the Oil Sands Mining and Upgrading 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 IQRE 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.
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 2023 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 reserves 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.

21 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Oil and Gas Reserves Tables and Notes
Summary of Company Gross Reserves
As of December 31, 2023
Forecast Prices and Costs

| Light and Medium Crude Oil (MMbbl) | Primary Heavy Crude Oil (MMbbl) | Pelican Lake Heavy Crude Oil (MMbbl) | Bitumen (Thermal Oil) (MMbbl) | Synthetic Crude Oil (MMbbl) | Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | Barrels of Oil Equivalent (MMBOE)
North America |  |  |  |  |  |  |  |
Proved |  |  |  |  |  |  |  |
Developed Producing | 76 |  | 106 |  | 203 |  | 653 |  | 6,827 |  | 4,720 |  | 138 |  | 8,790 |
Developed Non-Producing | 5 |  | 7 |  | — |  | 38 |  | — |  | 229 |  | 7 |  | 95 |
Undeveloped | 68 |  | 80 |  | 55 |  | 2,596 |  | 83 |  | 10,027 |  | 398 |  | 4,952 |
Total Proved | 149 |  | 193 |  | 258 |  | 3,287 |  | 6,910 |  | 14,976 |  | 543 |  | 13,836 |
Probable | 62 |  | 95 |  | 107 |  | 1,903 |  | 550 |  | 9,259 |  | 305 |  | 4,566 |
Total Proved plus Probable | 211 |  | 288 |  | 365 |  | 5,191 |  | 7,460 |  | 24,236 |  | 848 |  | 18,402 |
North Sea |  |  |  |  |  |  |  |
Proved |  |  |  |  |  |  |  |
Developed Producing | 5 |  |  |  |  |  | 1 |  |  | 5 |
Developed Non-Producing | — |  |  |  |  |  | — |  |  | — |
Undeveloped | 3 |  |  |  |  |  | 2 |  |  | 4 |
Total Proved | 8 |  |  |  |  |  | 3 |  |  | 9 |
Probable | 4 |  |  |  |  |  | 2 |  |  | 5 |
Total Proved plus Probable | 12 |  |  |  |  |  | 5 |  |  | 13 |
Offshore Africa |  |  |  |  |  |  |  |
Proved |  |  |  |  |  |  |  |
Developed Producing | 33 |  |  |  |  |  | 10 |  |  | 34 |
Developed Non-Producing | — |  |  |  |  |  | — |  |  | — |
Undeveloped | 28 |  |  |  |  |  | 16 |  |  | 31 |
Total Proved | 61 |  |  |  |  |  | 26 |  |  | 65 |
Probable | 21 |  |  |  |  |  | 18 |  |  | 24 |
Total Proved plus Probable | 81 |  |  |  |  |  | 44 |  |  | 89 |
Total Company |  |  |  |  |  |  |  |
Proved |  |  |  |  |  |  |  |
Developed Producing | 114 |  | 106 |  | 203 |  | 653 |  | 6,827 |  | 4,730 |  | 138 |  | 8,829 |
Developed Non-Producing | 5 |  | 7 |  | — |  | 38 |  | — |  | 229 |  | 7 |  | 95 |
Undeveloped | 100 |  | 80 |  | 55 |  | 2,596 |  | 83 |  | 10,045 |  | 398 |  | 4,986 |
Total Proved | 218 |  | 193 |  | 258 |  | 3,287 |  | 6,910 |  | 15,005 |  | 543 |  | 13,910 |
Probable | 87 |  | 95 |  | 107 |  | 1,903 |  | 550 |  | 9,279 |  | 305 |  | 4,594 |
Total Proved plus Probable | 305 |  | 288 |  | 365 |  | 5,191 |  | 7,460 |  | 24,284 |  | 848 |  | 18,504 |

Canadian Natural 2023 Annual Information Form | 22

Principal Documents Exhibits
Summary of Company Net Reserves
As of December 31, 2023
Forecast Prices and Costs

| Light and Medium Crude Oil (MMbbl) | Primary Heavy Crude Oil (MMbbl) | Pelican Lake Heavy Crude Oil (MMbbl) | Bitumen (Thermal Oil) (MMbbl) | Synthetic Crude Oil (MMbbl) | Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | Barrels of Oil Equivalent (MMBOE)
North America |  |  |  |  |  |  |  |
Proved |  |  |  |  |  |  |  |
Developed Producing | 64 |  | 86 |  | 154 |  | 485 |  | 5,607 |  | 4,220 |  | 108 |  | 7,208 |
Developed Non-Producing | 4 |  | 6 |  | — |  | 29 |  | — |  | 206 |  | 5 |  | 78 |
Undeveloped | 54 |  | 66 |  | 42 |  | 1,934 |  | 29 |  | 8,526 |  | 302 |  | 3,849 |
Total Proved | 123 |  | 158 |  | 196 |  | 2,448 |  | 5,636 |  | 12,952 |  | 416 |  | 11,136 |
Probable | 48 |  | 76 |  | 74 |  | 1,411 |  | 438 |  | 7,644 |  | 217 |  | 3,537 |
Total Proved plus Probable | 171 |  | 234 |  | 270 |  | 3,859 |  | 6,073 |  | 20,596 |  | 634 |  | 14,673 |
North Sea |  |  |  |  |  |  |  |
Proved |  |  |  |  |  |  |  |
Developed Producing | 5 |  |  |  |  |  | 1 |  |  | 5 |
Developed Non-Producing | — |  |  |  |  |  | — |  |  | — |
Undeveloped | 3 |  |  |  |  |  | 2 |  |  | 4 |
Total Proved | 8 |  |  |  |  |  | 3 |  |  | 9 |
Probable | 4 |  |  |  |  |  | 2 |  |  | 5 |
Total Proved plus Probable | 12 |  |  |  |  |  | 5 |  |  | 13 |
Offshore Africa |  |  |  |  |  |  |  |
Proved |  |  |  |  |  |  |  |
Developed Producing | 30 |  |  |  |  |  | 9 |  |  | 31 |
Developed Non-Producing | — |  |  |  |  |  | — |  |  | — |
Undeveloped | 23 |  |  |  |  |  | 13 |  |  | 25 |
Total Proved | 53 |  |  |  |  |  | 22 |  |  | 56 |
Probable | 16 |  |  |  |  |  | 14 |  |  | 19 |
Total Proved plus Probable | 69 |  |  |  |  |  | 36 |  |  | 75 |
Total Company |  |  |  |  |  |  |  |
Proved |  |  |  |  |  |  |  |
Developed Producing | 99 |  | 86 |  | 154 |  | 485 |  | 5,607 |  | 4,229 |  | 108 |  | 7,244 |
Developed Non-Producing | 4 |  | 6 |  | — |  | 29 |  | — |  | 206 |  | 5 |  | 79 |
Undeveloped | 81 |  | 66 |  | 42 |  | 1,934 |  | 29 |  | 8,542 |  | 302 |  | 3,878 |
Total Proved | 184 |  | 158 |  | 196 |  | 2,448 |  | 5,636 |  | 12,977 |  | 416 |  | 11,201 |
Probable | 69 |  | 76 |  | 74 |  | 1,411 |  | 438 |  | 7,660 |  | 217 |  | 3,561 |
Total Proved plus Probable | 252 |  | 234 |  | 270 |  | 3,859 |  | 6,073 |  | 20,637 |  | 634 |  | 14,761 |

23 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Reconciliation of Company Gross Reserves
As of December 31, 2023
Forecast Prices and Costs
TOTAL PROVED

North America | Light and Medium Crude Oil (MMbbl) | Primary Heavy Crude Oil (MMbbl) | Pelican Lake Heavy Crude Oil (MMbbl) | Bitumen (Thermal Oil) (MMbbl) | Synthetic Crude Oil (MMbbl) | Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | Barrels of Oil Equivalent (MMBOE)
December 31, 2022 | 150 |  | 179 |  | 262 |  | 3,284 |  | 6,873 |  | 13,589 |  | 486 |  | 13,501 |
Discoveries | — |  | — |  | — |  | — |  | — |  | 5 |  | — |  | 1 |
Extensions | 18 |  | 22 |  | — |  | 68 |  | 191 |  | 1,246 |  | 43 |  | 548 |
Infill Drilling | 8 |  | 6 |  | — |  | — |  | — |  | 638 |  | 35 |  | 156 |
Improved Recovery | — |  | — |  | 1 |  | 6 |  | 34 |  | — |  | — |  | 40 |
Acquisitions | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Dispositions | — |  | — |  | — |  | — |  | — |  | (7) |  | (1) |  | (2) |
Economic Factors | 1 |  | 1 |  | 1 |  | 1 |  | — |  | (81) |  | (2) |  | (12) |
Technical Revisions | (10) |  | 13 |  | 12 |  | 24 |  | (23) |  | 367 |  | 3 |  | 80 |
Production | (18) |  | (28) |  | (17) |  | (96) |  | (165) |  | (781) |  | (22) |  | (476) |
December 31, 2023 | 149 |  | 193 |  | 258 |  | 3,287 |  | 6,910 |  | 14,976 |  | 543 |  | 13,836 |
North Sea |  |  |  |  |  |  |  |
December 31, 2022 | 11 |  |  |  |  |  | 4 |  |  | 11 |
Discoveries | — |  |  |  |  |  | — |  |  | — |
Extensions | — |  |  |  |  |  | — |  |  | — |
Infill Drilling | — |  |  |  |  |  | — |  |  | — |
Improved Recovery | — |  |  |  |  |  | — |  |  | — |
Acquisitions | — |  |  |  |  |  | — |  |  | — |
Dispositions | — |  |  |  |  |  | — |  |  | — |
Economic Factors | — |  |  |  |  |  | — |  |  | — |
Technical Revisions | 2 |  |  |  |  |  | (1) |  |  | 2 |
Production | (5) |  |  |  |  |  | (1) |  |  | (5) |
December 31, 2023 | 8 |  |  |  |  |  | 3 |  |  | 9 |
Offshore Africa |  |  |  |  |  |  |  |
December 31, 2022 | 70 |  |  |  |  |  | 34 |  |  | 75 |
Discoveries | — |  |  |  |  |  | — |  |  | — |
Extensions | — |  |  |  |  |  | — |  |  | — |
Infill Drilling | — |  |  |  |  |  | — |  |  | — |
Improved Recovery | — |  |  |  |  |  | — |  |  | — |
Acquisitions | — |  |  |  |  |  | — |  |  | — |
Dispositions | — |  |  |  |  |  | — |  |  | — |
Economic Factors | — |  |  |  |  |  | — |  |  | — |
Technical Revisions | (4) |  |  |  |  |  | (4) |  |  | (5) |
Production | (5) |  |  |  |  |  | (4) |  |  | (6) |
December 31, 2023 | 61 |  |  |  |  |  | 26 |  |  | 65 |
Total Company |  |  |  |  |  |  |  |
December 31, 2022 | 231 |  | 179 |  | 262 |  | 3,284 |  | 6,873 |  | 13,627 |  | 486 |  | 13,587 |
Discoveries | — |  | — |  | — |  | — |  | — |  | 5 |  | — |  | 1 |
Extensions | 18 |  | 22 |  | — |  | 68 |  | 191 |  | 1,246 |  | 43 |  | 548 |
Infill Drilling | 8 |  | 6 |  | — |  | — |  | — |  | 638 |  | 35 |  | 156 |
Improved Recovery | — |  | — |  | 1 |  | 6 |  | 34 |  | — |  | — |  | 40 |
Acquisitions | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Dispositions | — |  | — |  | — |  | — |  | — |  | (7) |  | (1) |  | (2) |
Economic Factors | 1 |  | 1 |  | 1 |  | 1 |  | — |  | (81) |  | (2) |  | (12) |
Technical Revisions | (12) |  | 13 |  | 12 |  | 24 |  | (23) |  | 362 |  | 3 |  | 77 |
Production | (27) |  | (28) |  | (17) |  | (96) |  | (165) |  | (785) |  | (22) |  | (486) |
December 31, 2023 | 218 |  | 193 |  | 258 |  | 3,287 |  | 6,910 |  | 15,005 |  | 543 |  | 13,910 |

Canadian Natural 2023 Annual Information Form | 24

Principal Documents Exhibits
TOTAL PROBABLE

North America | Light and Medium Crude Oil (MMbbl) | Primary Heavy Crude Oil (MMbbl) | Pelican Lake Heavy Crude Oil (MMbbl) | Bitumen (Thermal Oil) (MMbbl) | Synthetic Crude Oil (MMbbl) | Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | Barrels of Oil Equivalent (MMBOE)
December 31, 2022 | 60 |  | 93 |  | 114 |  | 1,901 |  | 535 |  | 8,619 |  | 285 |  | 4,425 |
Discoveries | — |  | — |  | — |  | — |  | — |  | 1 |  | — |  | — |
Extensions | 10 |  | 15 |  | — |  | 29 |  | 18 |  | 764 |  | 31 |  | 231 |
Infill Drilling | 3 |  | 2 |  | — |  | — |  | — |  | 324 |  | 13 |  | 72 |
Improved Recovery | — |  | — |  | — |  | 1 |  | 17 |  | — |  | — |  | 19 |
Acquisitions | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Dispositions | — |  | — |  | — |  | — |  | — |  | (2) |  | — |  | — |
Economic Factors | — |  | — |  | — |  | — |  | — |  | (7) |  | — |  | — |
Technical Revisions | (12) |  | (15) |  | (7) |  | (28) |  | (20) |  | (441) |  | (24) |  | (180) |
Production | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
December 31, 2023 | 62 |  | 95 |  | 107 |  | 1,903 |  | 550 |  | 9,259 |  | 305 |  | 4,566 |
North Sea |  |  |  |  |  |  |  |
December 31, 2022 | 4 |  |  |  |  |  | 3 |  |  | 5 |
Discoveries | — |  |  |  |  |  | — |  |  | — |
Extensions | — |  |  |  |  |  | — |  |  | — |
Infill Drilling | — |  |  |  |  |  | — |  |  | — |
Improved Recovery | — |  |  |  |  |  | — |  |  | — |
Acquisitions | — |  |  |  |  |  | — |  |  | — |
Dispositions | — |  |  |  |  |  | — |  |  | — |
Economic Factors | — |  |  |  |  |  | — |  |  | — |
Technical Revisions | — |  |  |  |  |  | (1) |  |  | — |
Production | — |  |  |  |  |  | — |  |  | — |
December 31, 2023 | 4 |  |  |  |  |  | 2 |  |  | 5 |
Offshore Africa |  |  |  |  |  |  |  |
December 31, 2022 | 25 |  |  |  |  |  | 21 |  |  | 29 |
Discoveries | — |  |  |  |  |  | — |  |  | — |
Extensions | — |  |  |  |  |  | — |  |  | — |
Infill Drilling | — |  |  |  |  |  | — |  |  | — |
Improved Recovery | — |  |  |  |  |  | — |  |  | — |
Acquisitions | — |  |  |  |  |  | — |  |  | — |
Dispositions | — |  |  |  |  |  | — |  |  | — |
Economic Factors | — |  |  |  |  |  | — |  |  | — |
Technical Revisions | (4) |  |  |  |  |  | (3) |  |  | (5) |
Production | — |  |  |  |  |  | — |  |  | — |
December 31, 2023 | 21 |  |  |  |  |  | 18 |  |  | 24 |
Total Company |  |  |  |  |  |  |  |
December 31, 2022 | 89 |  | 93 |  | 114 |  | 1,901 |  | 535 |  | 8,643 |  | 285 |  | 4,458 |
Discoveries | — |  | — |  | — |  | — |  | — |  | 1 |  | — |  | — |
Extensions | 10 |  | 15 |  | — |  | 29 |  | 18 |  | 764 |  | 31 |  | 231 |
Infill Drilling | 3 |  | 2 |  | — |  | — |  | — |  | 324 |  | 13 |  | 72 |
Improved Recovery | — |  | — |  | — |  | 1 |  | 17 |  | — |  | — |  | 19 |
Acquisitions | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Dispositions | — |  | — |  | — |  | — |  | — |  | (2) |  | — |  | — |
Economic Factors | — |  | — |  | — |  | — |  | — |  | (7) |  | — |  | — |
Technical Revisions | (16) |  | (15) |  | (7) |  | (28) |  | (20) |  | (445) |  | (24) |  | (185) |
Production | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
December 31, 2023 | 87 |  | 95 |  | 107 |  | 1,903 |  | 550 |  | 9,279 |  | 305 |  | 4,594 |

25 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
TOTAL PROVED PLUS PROBABLE

North America | Light and Medium Crude Oil (MMbbl) | Primary Heavy Crude Oil (MMbbl) | Pelican Lake Heavy Crude Oil (MMbbl) | Bitumen (Thermal Oil) (MMbbl) | Synthetic Crude Oil (MMbbl) | Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | Barrels of Oil Equivalent (MMBOE)
December 31, 2022 | 210 |  | 272 |  | 376 |  | 5,186 |  | 7,408 |  | 22,209 |  | 772 |  | 17,926 |
Discoveries | — |  | — |  | — |  | — |  | — |  | 7 |  | 1 |  | 2 |
Extensions | 28 |  | 37 |  | — |  | 97 |  | 209 |  | 2,009 |  | 74 |  | 780 |
Infill Drilling | 12 |  | 8 |  | — |  | — |  | — |  | 962 |  | 48 |  | 227 |
Improved Recovery | — |  | — |  | 1 |  | 7 |  | 51 |  | — |  | — |  | 58 |
Acquisitions | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Dispositions | — |  | — |  | — |  | — |  | — |  | (8) |  | (1) |  | (2) |
Economic Factors | 1 |  | 1 |  | 1 |  | 1 |  | — |  | (88) |  | (2) |  | (12) |
Technical Revisions | (22) |  | (2) |  | 4 |  | (4) |  | (43) |  | (74) |  | (21) |  | (100) |
Production | (18) |  | (28) |  | (17) |  | (96) |  | (165) |  | (781) |  | (22) |  | (476) |
December 31, 2023 | 211 |  | 288 |  | 365 |  | 5,191 |  | 7,460 |  | 24,236 |  | 848 |  | 18,402 |
North Sea |  |  |  |  |  |  |  |
December 31, 2022 | 15 |  |  |  |  |  | 7 |  |  | 16 |
Discoveries | — |  |  |  |  |  | — |  |  | — |
Extensions | — |  |  |  |  |  | — |  |  | — |
Infill Drilling | — |  |  |  |  |  | — |  |  | — |
Improved Recovery | — |  |  |  |  |  | — |  |  | — |
Acquisitions | — |  |  |  |  |  | — |  |  | — |
Dispositions | — |  |  |  |  |  | — |  |  | — |
Economic Factors | — |  |  |  |  |  | — |  |  | — |
Technical Revisions | 2 |  |  |  |  |  | (2) |  |  | 2 |
Production | (5) |  |  |  |  |  | (1) |  |  | (5) |
December 31, 2023 | 12 |  |  |  |  |  | 5 |  |  | 13 |
Offshore Africa |  |  |  |  |  |  |  |
December 31, 2022 | 95 |  |  |  |  |  | 55 |  |  | 104 |
Discoveries | — |  |  |  |  |  | — |  |  | — |
Extensions | — |  |  |  |  |  | — |  |  | — |
Infill Drilling | — |  |  |  |  |  | — |  |  | — |
Improved Recovery | — |  |  |  |  |  | — |  |  | — |
Acquisitions | — |  |  |  |  |  | — |  |  | — |
Dispositions | — |  |  |  |  |  | — |  |  | — |
Economic Factors | — |  |  |  |  |  | — |  |  | — |
Technical Revisions | (9) |  |  |  |  |  | (7) |  |  | (10) |
Production | (5) |  |  |  |  |  | (4) |  |  | (6) |
December 31, 2023 | 81 |  |  |  |  |  | 44 |  |  | 89 |
Total Company |  |  |  |  |  |  |  |
December 31, 2022 | 320 |  | 272 |  | 376 |  | 5,186 |  | 7,408 |  | 22,270 |  | 772 |  | 18,046 |
Discoveries | — |  | — |  | — |  | — |  | — |  | 7 |  | 1 |  | 2 |
Extensions | 28 |  | 37 |  | — |  | 97 |  | 209 |  | 2,009 |  | 74 |  | 780 |
Infill Drilling | 12 |  | 8 |  | — |  | — |  | — |  | 962 |  | 48 |  | 227 |
Improved Recovery | — |  | — |  | 1 |  | 7 |  | 51 |  | — |  | — |  | 58 |
Acquisitions | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Dispositions | — |  | — |  | — |  | — |  | — |  | (8) |  | (1) |  | (2) |
Economic Factors | 1 |  | 1 |  | 1 |  | 1 |  | — |  | (88) |  | (2) |  | (12) |
Technical Revisions | (28) |  | (2) |  | 4 |  | (4) |  | (43) |  | (83) |  | (21) |  | (108) |
Production | (27) |  | (28) |  | (17) |  | (96) |  | (165) |  | (785) |  | (22) |  | (486) |
December 31, 2023 | 305 |  | 288 |  | 365 |  | 5,191 |  | 7,460 |  | 24,284 |  | 848 |  | 18,504 |

Canadian Natural 2023 Annual Information Form | 26

Principal Documents Exhibits
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.
7.2023 reserves reconciliation highlights:
Total Proved Crude Oil, Bitumen (Thermal Oil) and NGLs reserves increased by 93 MMbbl:
▪Extensions: Increase of 341 MMbbl primarily due to pit extensions at Oil Sands Mining and Upgrading (SCO) and extension drilling/future offset additions at various Bitumen (Thermal Oil), natural gas (NGLs), Primary Heavy Crude Oil, and Light Crude Oil properties.
▪Infill Drilling: Increase of 50 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs), Light Crude Oil and Primary Heavy Crude Oil properties.
▪Improved Recovery: Increase of 40 MMbbl primarily due to increased recovery at Oil Sands Mining and Upgrading (SCO), and various Bitumen (Thermal Oil) and Primary Heavy Crude Oil properties.
▪Dispositions: Decrease of 1 MMbbl primarily due to dispositions from various natural gas (NGLs) properties in Alberta.
▪Economic Factors: Increase of 1 MMbbl due to changes in product pricing.

27 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
▪Technical Revisions: Increase of 17 MMbbl primarily due to improved performance at various Bitumen (Thermal Oil), Primary Heavy Crude Oil, Pelican Lake Heavy Crude Oil and natural gas (NGLs) properties, partially offset by reduced performance at various Light Crude Oil properties and mine plan changes at Oil Sands Mining and Upgrading (SCO).
▪Production: Decrease of 355 MMbbl.
Total Proved Natural Gas reserves increased by 1,377 Bcf:
▪Discovery: Increase of 5 Bcf due to activity in various Natural Gas properties in Alberta.
▪Extensions: Increase of 1,246 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 638 Bcf primarily due to infill drilling/future offset additions in the Montney and other unconventional formations of northwest Alberta and northeast British Columbia.
▪Dispositions: Decrease of 7 Bcf primarily due to property dispositions from various Natural Gas properties in Alberta.
▪Economic Factors: Decrease of 81 Bcf due to lower product pricing.
▪Technical Revisions: Increase of 362 Bcf primarily due to category transfers from probable to proved, and positive revisions in various North America core areas as a result of improved performance.
▪Production: Decrease of 785 Bcf.
Total Proved plus Probable Crude Oil, Bitumen and NGLs reserves increased by 123 MMbbl:
▪Discovery: Increase of 1 MMbbl due to activity in various natural gas (NGLs) properties in Alberta.
▪Extensions: Increase of 445 MMbbl primarily due to pit extensions as Oil Sands Mining and Upgrading (SCO) and extension drilling/future offset additions at various Bitumen (Thermal Oil), natural gas (NGLs), Primary Heavy Crude Oil, and Light Crude Oil properties.
▪Infill Drilling: Increase of 67 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs), Light Crude Oil and Primary Heavy Crude Oil properties.
▪Improved Recovery: Increase of 58 MMbbl primarily due to increased recovery at Oil Sands Mining and Upgrading (SCO), and various Bitumen (Thermal Oil) and Pelican Lake Heavy Crude Oil properties.
▪Dispositions: Decrease of 1 MMbbl primarily due to dispositions from various natural gas (NGLs) properties in Alberta.
▪Economic Factors: Increase of 2 MMbbl due to changes in product pricing.
▪Technical Revisions: Decrease of 94 MMbbl primarily due to mine plan changes at Oil Sands Mining and Upgrading, and performance at various Light Crude Oil, natural gas (NGLs), Bitumen (Thermal Oil) and Primary Heavy Crude Oil properties, partially offset by improved performance at Pelican Lake Heavy Crude Oil properties.
▪Production: Decrease of 355 MMbbl.
Total Proved plus Probable Natural Gas reserves increased by 2,013 Bcf:
▪Discovery: Increase of 7 Bcf due to activity in Natural Gas properties in Alberta.
▪Extensions: Increase of 2,009 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 962 Bcf primarily due to infill drilling/future offset additions in the Montney and other unconventional formations of northwest Alberta and northeast British Columbia.
▪Dispositions: Decrease of 8 Bcf primarily due to property dispositions from various Natural Gas properties in Alberta.
▪Economic Factors: Decrease of 88 Bcf due to lower product pricing.
▪Technical Revisions: Decrease of 83 Bcf primarily due to decreased performance at various Natural Gas properties.
▪Production: Decrease of 785 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.

Canadian Natural 2023 Annual Information Form | 28

Principal Documents Exhibits
Future Net Revenue Tables and Notes
The following tables summarize the future net revenue as of December 31, 2023 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 Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as of December 31, 2023 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, 2023
Forecast Prices and Costs

($ millions) | Discount @ 0% | Discount @ 5% | Discount @ 10% | Discount @ 15% | Discount @ 20% | Unit Value Discounted at 10%/year ($/BOE)
North America |  |  |  |  |  |
Proved |  |  |  |  |  |
Developed Producing | 479,029 |  | 186,621 |  | 106,649 |  | 75,062 |  | 58,825 |  | 14.80 |
Developed Non-Producing | 3,410 |  | 1,182 |  | 756 |  | 588 |  | 486 |  | 9.65 |
Undeveloped | 173,853 |  | 85,135 |  | 46,155 |  | 27,588 |  | 17,748 |  | 11.99 |
Total Proved | 656,292 |  | 272,938 |  | 153,560 |  | 103,238 |  | 77,059 |  | 13.79 |
Probable | 209,525 |  | 68,651 |  | 31,952 |  | 18,752 |  | 12,706 |  | 9.03 |
Total Proved plus Probable | 865,817 |  | 341,588 |  | 185,512 |  | 121,990 |  | 89,765 |  | 12.64 |
North Sea |  |  |  |  |  |
Proved |  |  |  |  |  |
Developed Producing | (1,851) |  | (1,444) |  | (1,167) |  | (971) |  | (827) |  | (239.98) |
Developed Non-Producing | 12 |  | 11 |  | 10 |  | 9 |  | 8 |  | 87.81 |
Undeveloped | 158 |  | 134 |  | 116 |  | 101 |  | 88 |  | 32.19 |
Total Proved | (1,681) |  | (1,299) |  | (1,042) |  | (862) |  | (731) |  | (121.55) |
Probable | 219 |  | 175 |  | 143 |  | 120 |  | 101 |  | 30.98 |
Total Proved plus Probable | (1,462) |  | (1,124) |  | (898) |  | (742) |  | (630) |  | (68.07) |
Offshore Africa |  |  |  |  |  |
Proved |  |  |  |  |  |
Developed Producing | 674 |  | 579 |  | 464 |  | 359 |  | 272 |  | 14.92 |
Developed Non-Producing | 6 |  | 6 |  | 5 |  | 4 |  | 4 |  | 78.50 |
Undeveloped | 1,565 |  | 1,033 |  | 700 |  | 482 |  | 334 |  | 27.81 |
Total Proved | 2,245 |  | 1,618 |  | 1,169 |  | 845 |  | 610 |  | 20.75 |
Probable | 1,431 |  | 960 |  | 672 |  | 487 |  | 364 |  | 35.90 |
Total Proved plus Probable | 3,676 |  | 2,579 |  | 1,841 |  | 1,333 |  | 974 |  | 24.53 |
Total Company |  |  |  |  |  |
Proved |  |  |  |  |  |
Developed Producing | 477,852 |  | 185,756 |  | 105,945 |  | 74,450 |  | 58,269 |  | 14.62 |
Developed Non-Producing | 3,429 |  | 1,198 |  | 771 |  | 601 |  | 498 |  | 9.82 |
Undeveloped | 175,576 |  | 86,303 |  | 46,971 |  | 28,170 |  | 18,170 |  | 12.11 |
Total Proved | 656,857 |  | 273,257 |  | 153,687 |  | 103,221 |  | 76,938 |  | 13.72 |
Probable | 211,174 |  | 69,786 |  | 32,767 |  | 19,359 |  | 13,171 |  | 9.20 |
Total Proved plus Probable | 868,031 |  | 343,043 |  | 186,454 |  | 122,580 |  | 90,109 |  | 12.63 |

29 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Summary of Net Present Values of Future Net Revenue After Income Taxes
As of December 31, 2023
Forecast Prices and Costs

($ millions) | Discount @ 0% | Discount @ 5% | Discount @ 10% | Discount @ 15% | Discount @ 20%
North America |  |  |  |  |
Proved |  |  |  |  |
Developed Producing | 369,022 |  | 144,276 |  | 82,796 |  | 58,476 |  | 45,947 |
Developed Non-Producing | 2,917 |  | 930 |  | 573 |  | 441 |  | 362 |
Undeveloped | 133,196 |  | 64,445 |  | 34,422 |  | 20,192 |  | 12,692 |
Total Proved | 505,135 |  | 209,651 |  | 117,792 |  | 79,109 |  | 59,001 |
Probable | 160,081 |  | 52,229 |  | 24,188 |  | 14,126 |  | 9,530 |
Total Proved plus Probable | 665,216 |  | 261,880 |  | 141,980 |  | 93,234 |  | 68,531 |
North Sea |  |  |  |  |
Proved |  |  |  |  |
Developed Producing | (1,252) |  | (942) |  | (739) |  | (600) |  | (501) |
Developed Non-Producing | 12 |  | 11 |  | 10 |  | 9 |  | 8 |
Undeveloped | 158 |  | 134 |  | 116 |  | 101 |  | 88 |
Total Proved | (1,082) |  | (797) |  | (614) |  | (491) |  | (405) |
Probable | 219 |  | 175 |  | 143 |  | 120 |  | 101 |
Total Proved plus Probable | (864) |  | (622) |  | (470) |  | (371) |  | (304) |
Offshore Africa |  |  |  |  |
Proved |  |  |  |  |
Developed Producing | 451 |  | 420 |  | 344 |  | 265 |  | 195 |
Developed Non-Producing | 6 |  | 5 |  | 5 |  | 4 |  | 4 |
Undeveloped | 1,187 |  | 780 |  | 523 |  | 355 |  | 240 |
Total Proved | 1,644 |  | 1,205 |  | 872 |  | 624 |  | 439 |
Probable | 1,110 |  | 751 |  | 529 |  | 386 |  | 290 |
Total Proved plus Probable | 2,754 |  | 1,956 |  | 1,401 |  | 1,010 |  | 728 |
Total Company |  |  |  |  |
Proved |  |  |  |  |
Developed Producing | 368,220 |  | 143,753 |  | 82,401 |  | 58,141 |  | 45,641 |
Developed Non-Producing | 2,935 |  | 946 |  | 588 |  | 454 |  | 374 |
Undeveloped | 134,541 |  | 65,359 |  | 35,061 |  | 20,647 |  | 13,019 |
Total Proved | 505,696 |  | 210,059 |  | 118,051 |  | 79,242 |  | 59,035 |
Probable | 161,410 |  | 53,155 |  | 24,861 |  | 14,631 |  | 9,921 |
Total Proved plus Probable | 667,106 |  | 263,214 |  | 142,912 |  | 93,873 |  | 68,955 |

Canadian Natural 2023 Annual Information Form | 30

Principal Documents Exhibits
Total Future Net Revenue (Undiscounted)
As of December 31, 2023
Forecast Prices and Costs

| North America | North Sea | Offshore Africa | Total Company
($ millions) | Total Proved | Total Proved plus Probable | Total Proved | Total Proved plus Probable | Total Proved | Total Proved plus Probable | Total Proved | Total Proved plus Probable
Revenue | 1,493,129 |  | 1,919,471 |  | 933 |  | 1,465 |  | 6,250 |  | 8,350 |  | 1,500,312 |  | 1,929,286 |
Royalties | 290,898 |  | 385,844 |  | — |  | — |  | 210 |  | 283 |  | 291,108 |  | 386,127 |
Production Costs | 428,384 |  | 525,653 |  | 577 |  | 875 |  | 1,792 |  | 2,126 |  | 430,752 |  | 528,655 |
Development Costs | 95,791 |  | 119,151 |  | 105 |  | 119 |  | 1,486 |  | 1,731 |  | 97,382 |  | 121,001 |
ADR Costs for Future Development | 1,314 |  | 1,941 |  | — |  | — |  | 34 |  | 51 |  | 1,348 |  | 1,992 |
Future Net Revenue Before Income Taxes Excluding ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | 676,742 |  | 886,881 |  | 252 |  | 471 |  | 2,728 |  | 4,158 |  | 679,722 |  | 891,510 |
ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | 20,450 |  | 21,064 |  | 1,933 |  | 1,933 |  | 482 |  | 482 |  | 22,865 |  | 23,480 |
Future Net Revenue Before Income Taxes Including ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | 656,292 |  | 865,817 |  | (1,681) |  | (1,462) |  | 2,245 |  | 3,676 |  | 656,857 |  | 868,031 |
Income Taxes | 151,158 |  | 200,601 |  | (598) |  | (598) |  | 602 |  | 922 |  | 151,161 |  | 200,925 |
Future Net Revenue After Income Taxes | 505,135 |  | 665,216 |  | (1,082) |  | (864) |  | 1,644 |  | 2,754 |  | 505,696 |  | 667,106 |

31 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Future Net Revenue By Product Type
As of December 31, 2023
Forecast Prices and Costs
Total Proved

Product Type | Future Net Revenue Before Income Taxes (discounted at 10%/year) ($ millions) | Unit Value ($/BOE)
Light and Medium Crude Oil (including solution gas and other by-products) | 6,291 |  | 16.85 |
Primary Heavy Crude Oil (including solution gas) | 3,281 |  | 20.10 |
Pelican Lake Heavy Crude Oil (including solution gas) | 3,956 |  | 20.18 |
Bitumen (Thermal Oil) | 39,447 |  | 16.11 |
Synthetic Crude Oil | 89,300 |  | 15.84 |
Natural Gas (including by-products but excluding solution gas and by-products from crude oil wells) | 16,787 |  | 7.04 |
Total Excluding ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | 159,063 |  | 14.20 |
ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | (5,376) |  |
Total Including ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | 153,687 |  | 13.72 |
Total Proved plus Probable |  |
Product Type | Future Net Revenue Before Income Taxes (discounted at 10%/year) ($ millions) | Unit Value ($/BOE)
Light and Medium Crude Oil (including solution gas and other by-products) | 9,230 |  | 17.95 |
Primary Heavy Crude Oil (including solution gas) | 4,985 |  | 20.72 |
Pelican Lake Heavy Crude Oil (including solution gas) | 5,091 |  | 18.82 |
Bitumen (Thermal Oil) | 50,608 |  | 13.12 |
Synthetic Crude Oil | 96,225 |  | 15.84 |
Natural Gas (including by-products but excluding solution gas and by-products from crude oil wells) | 25,726 |  | 6.76 |
Total Excluding ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | 191,866 |  | 13.00 |
ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | (5,412) |  |
Total Including ADR Costs for Existing Development (Equivalent to the Financial Statement ARO) | 186,454 |  | 12.63 |

Canadian Natural 2023 Annual Information Form | 32

Principal Documents Exhibits
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 Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as of December 31, 2023 and forecast estimates of ADR costs attributable to future development activity. The Company’s total 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 the proposed federal Greenhouse Gas Pollution Pricing Act, which reaches $170/tonne in 2030. For reserves in the North Sea, future net revenue includes carbon costs associated with the UK Emissions Trading Scheme.
3.Unit values ($/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, 2023 and the annual MD&A for the year ended December 31, 2023, da ted February 28, 2024.
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, GLJ and McDaniel & Associates Consultants Ltd. ("McDaniel"), dated December 31, 2023. The following is a summary of the 3-consultant-average price forecast. All prices increase at a rate of 2% per year after 2028.

|  | 2024 | 2025 | 2026 | 2027 | 2028
Crude Oil and NGLs |  |  |  |  |  |
WTI | US$/bbl | 73.67 |  | 74.98 |  | 76.14 |  | 77.66 |  | 79.22 |
WCS | C$/bbl | 76.74 |  | 79.77 |  | 81.12 |  | 82.88 |  | 85.04 |
Canadian Light Sweet | C$/bbl | 92.91 |  | 95.04 |  | 96.07 |  | 97.99 |  | 99.95 |
Cromer LSB | C$/bbl | 93.57 |  | 95.86 |  | 96.46 |  | 98.39 |  | 100.36 |
Edmonton C5+ | C$/bbl | 96.79 |  | 98.75 |  | 100.71 |  | 102.72 |  | 104.78 |
Brent | US$/bbl | 78.00 |  | 79.18 |  | 80.36 |  | 81.79 |  | 83.41 |
Natural Gas |  |  |  |  |  |
AECO | C$/MMBtu | 2.20 |  | 3.37 |  | 4.05 |  | 4.13 |  | 4.21 |
BC Westcoast Station 2 | C$/MMBtu | 2.06 |  | 3.25 |  | 3.93 |  | 4.01 |  | 4.09 |
Henry Hub | US$/MMBtu | 2.75 |  | 3.64 |  | 4.02 |  | 4.10 |  | 4.18 |

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 and bitumen (thermal oil) reserves.
▪“Canadian Light Sweet” refers to the price of light gravity (40 o 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 (35 o 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 bitumen (thermal oil) reserves.
▪“Brent” refers to the benchmark price for European, African and Middle Eastern crude oil; reference price used in the preparation of North Sea and Offshore Africa light crude oil reserves.

33 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
▪“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 2023, the methodology used by Sproule, 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 Compa ny’s 2023 average pricing, net of blending costs and excluding risk management activities, was $98.49/bbl for light and medium crude oil, $75.67/bbl for primary heavy crude oil, $77.69/bbl for Pelican Lake heavy crude oil, $67.62/bbl for bitumen (thermal oil), $100.06/bbl for SCO, $53.04/bbl for NGLs, and $3.10/Mcf for natur al gas.
5.Production and capital costs are escalated at the 3-consultant-average cost inflation rate of 0% per year for 2024 and 2% per year for 2025 and beyond for all products.
6.The 3-consultant-average foreign exchange rate used in the 2023 evalu ation was 0.7517 US$/C$ for 2024 and 2025 and 0.7550 US$/C$ for 2026 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
Year | Light and Medium Crude Oil (MMbbl) | Primary Heavy Crude Oil (MMbbl) | Pelican Lake Heavy Crude Oil (MMbbl) | Bitumen (Thermal Oil) (MMbbl) | Synthetic Crude Oil (MMbbl) | Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | Barrels of Oil Equivalent (MMBOE)
2021 First Attributed | 2 |  | 5 |  | — |  | 119 |  | — |  | 2,068 |  | 69 |  | 541 |
Total | 115 |  | 74 |  | 56 |  | 2,012 |  | 37 |  | 7,413 |  | 283 |  | 3,812 |
2022 First Attributed | 7 |  | 9 |  | — |  | 693 |  | 37 |  | 870 |  | 54 |  | 945 |
Total | 93 |  | 73 |  | 55 |  | 2,604 |  | 37 |  | 8,332 |  | 337 |  | 4,587 |
2023 First Attributed | 26 |  | 24 |  | — |  | 68 |  | 35 |  | 2,063 |  | 82 |  | 579 |
Total | 100 |  | 80 |  | 55 |  | 2,596 |  | 83 |  | 10,045 |  | 398 |  | 4,986 |

Canadian Natural 2023 Annual Information Form | 34

Principal Documents Exhibits

Probable Undeveloped
Year | Light and Medium Crude Oil (MMbbl) | Primary Heavy Crude Oil (MMbbl) | Pelican Lake Heavy Crude Oil (MMbbl) | Bitumen (Thermal Oil) (MMbbl) | Synthetic Crude Oil (MMbbl) | Natural Gas (Bcf) | Natural Gas Liquids (MMbbl) | Barrels of Oil Equivalent (MMBOE)
2021 First Attributed | 2 |  | 3 |  | — |  | 39 |  | — |  | 2,037 |  | 60 |  | 443 |
Total | 58 |  | 57 |  | 27 |  | 1,467 |  | 106 |  | 6,711 |  | 183 |  | 3,017 |
2022 First Attributed | 3 |  | 10 |  | — |  | 195 |  | 13 |  | 953 |  | 72 |  | 451 |
Total | 39 |  | 64 |  | 28 |  | 1,632 |  | 13 |  | 7,073 |  | 239 |  | 3,193 |
2023 First Attributed | 13 |  | 15 |  | — |  | 30 |  | 18 |  | 1,076 |  | 43 |  | 299 |
Total | 48 |  | 64 |  | 27 |  | 1,635 |  | 18 |  | 7,717 |  | 257 |  | 3,335 |

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, the North Sea 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.Bitumen (Thermal Oil) development plans are designed to optimize the operation and deliver production for the life of the facilities over the next fifty years.
4.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.

35 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
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, 2023. 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 Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as of December 31, 2023 and forecast estimates of ADR costs attributable to future development activity.

Future Development Costs (Undiscounted)
($ millions) | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total | Total Discounted at 10%
Total Proved |  |  |  |  |  |  |  |
North America | 3,848 |  | 4,004 |  | 5,268 |  | 4,844 |  | 4,397 |  | 73,430 |  | 95,791 |  | 34,879 |
North Sea | 44 |  | 21 |  | 19 |  | 15 |  | 2 |  | 2 |  | 105 |  | 90 |
Offshore Africa | 249 |  | 488 |  | 379 |  | 78 |  | 52 |  | 239 |  | 1,486 |  | 1,167 |
Total Company | 4,141 |  | 4,514 |  | 5,667 |  | 4,937 |  | 4,452 |  | 73,672 |  | 97,382 |  | 36,136 |
Total Proved plus Probable |  |  |  |  |  |  |  |
North America | 4,005 |  | 4,385 |  | 5,517 |  | 5,231 |  | 4,860 |  | 95,154 |  | 119,151 |  | 40,281 |
North Sea | 44 |  | 21 |  | 19 |  | 15 |  | 7 |  | 12 |  | 119 |  | 98 |
Offshore Africa | 255 |  | 539 |  | 429 |  | 78 |  | 52 |  | 377 |  | 1,731 |  | 1,317 |
Total Company | 4,305 |  | 4,945 |  | 5,965 |  | 5,324 |  | 4,919 |  | 95,543 |  | 121,001 |  | 41,696 |

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.

Canadian Natural 2023 Annual Information Form | 36

Principal Documents Exhibits
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, 2023 and 2022.

| 2023 Average Daily Production Rates | 2022 Average Daily Production Rates
Region | Crude Oil & NGLs (bbl) | Natural Gas (MMcf) | Crude Oil & NGLs (bbl) | Natural Gas (MMcf)
North America |  |  |  |
Northeast British Columbia | 21,585 |  | 889 |  | 24,187 |  | 880 |
Northwest Alberta | 63,654 |  | 869 |  | 59,712 |  | 808 |
Northern Plains | 394,527 |  | 180 |  | 378,374 |  | 173 |
Southern Plains | 12,507 |  | 198 |  | 13,446 |  | 210 |
Southeast Saskatchewan | 3,827 |  | 3 |  | 4,252 |  | 3 |
Oil Sands Mining & Upgrading | 451,339 |  | — |  | 425,945 |  | — |
North America Total | 947,439 |  | 2,139 |  | 905,916 |  | 2,075 |
International |  |  |  |
North Sea UK Sector | 12,639 |  | 2 |  | 12,890 |  | 2 |
Offshore Africa | 13,452 |  | 11 |  | 14,343 |  | 13 |
International Total | 26,091 |  | 12 |  | 27,233 |  | 15 |
Company Total | 973,530 |  | 2,151 |  | 933,149 |  | 2,090 |

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 also 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.

37 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Northwest Alberta
This region is located west of Edmonton, Alberta along the border of British Columbia and Alberta and provides a premium land base in the deep basin, multi-zone, liquids-rich natural gas and light crude oil fairway. Northwest Alberta has a significant Montney and Spirit River land base, and provides exploration and development opportunities in combination with an extensive portfolio of owned and operated infrastructure. In this region, the Company produces liquids rich natural gas from multiple, often technically complex horizons, with formation depths ranging from 700 to 4,500 meters. Locations are identified with two dimensional and three dimensional seismic to predict channel and shoreface fairways. The southwest portion of this region also contains significant Foothills assets with natural gas produced from the deep Mississippian and Triassic aged reservoirs.
Northern Plains
This region starts just south of Edmonton, Alberta and extends north to Fort McMurray, Alberta and from northwest Alberta into western Saskatchewan. Over most of the region, both sweet and sour natural gas reserves are produced from numerous productive horizons at depths up to approximately 1,500 meters. In the southwest portion of the region, light crude oil and NGLs are also encountered at slightly greater depths. The Company targets low-risk exploration and development opportunities in this area.
Near Lloydminster, Alberta, reserves of primary heavy crude oil (averaging 10°-14° API) and natural gas are produced through conventional vertical, slant and horizontal well bores from a number of productive horizons at depths up to 1,000 meters. The energy required to flow the heavy crude oil to the wellbore in this type of heavy crude oil reservoir comes from solution gas. The crude oil viscosity and the reservoir quality will determine the amount of crude oil produced from the reservoir. A key component to maintaining profitability in the production of heavy crude oil is to be an effective and efficient producer. The Company continues to control costs by holding a dominant position that includes a significant land base and an extensive infrastructure of batteries and disposal facilities.

Canadian Natural 2023 Annual Information Form | 38

Principal Documents Exhibits
In this region, the Company’s holdings of primary heavy crude oil production are the result of Crown land purchases and acquisitions. The Company's 100% owned ECHO Pipeline system is also located in this region. The ECHO Pipeline has a capacity of up to 78,000 bbl/d, which enables the Company to transport its own production volumes at a reduced production cost. This pipeline enhances the Company’s ability to control the full spectrum of costs associated with the development and marketing of its heavy crude oil.
Included in the northern part of this region, approximately 200 miles north of Edmonton, Alberta are the Company’s holdings at Pelican Lake. These assets produce Pelican Lake heavy crude oil from the Wabasca formation with gravities of 12°-17° API. Production expenses are low due to the absence of sand production and its associated disposal requirements, as well as the gathering and pipeline facilities in place. The Company has the major ownership position in the necessary infrastructure, roads, drilling pads, gathering and sales pipelines, batteries, gas plants and compressors, to ensure economic development of the large crude oil pool located on the lands, including the 100% owned and operated Pelican Lake Pipeline and three major oil batteries with a capacity of 85,000 bbl/d. The Company is using an EOR scheme through polymer flooding to increase the ultimate recoveries from the field.
Production of bitumen (thermal oil) from the 100% owned Primrose and Wolf Lake fields located near Bonnyville, Alberta, involves processes that utilize steam to increase the recovery of the bitumen. The processes employed by the Company are CSS, SAGD and steamflood. These recovery processes inject steam to heat the bitumen deposits, reducing the viscosity and thereby improving its flow characteristics. There is also an infrastructure of gathering systems and a processing plant at Wolf Lake with capacity of 140,000 bbl/d. The Company holds a 50% interest in a co-generation facility capable of producing 84 megawatts of electricity. The Company continues to optimize the CSS, and steamflood processes which results in significant improvements in well productivity and in ultimate bitumen recovery.
The Company has two 100% owned thermal SAGD facilities in the Kirby area located near Lac La Biche, Alberta with infrastructure and total plant processing capacity of 80,000 bbl/d.
The Company has a 100% interest in the operating thermal SAGD assets at Jackfish and in the undeveloped Pike lands located adjacent to Jackfish. The infrastructure at Jackfish consists of three processing plants and gathering systems that have a combined capacity of 120,000 bbl/d. The Company approved the decision to proceed with the development of the Pike 1 project. Drilling and pipeline development in support of the Pike 1 project is targeted to commence in late 2024. The Pike 1 project is targeted to add approximately 25,000 bbl/d upon completion, which is anticipated in 2027.
Southern Plains and Southeast Saskatchewan
The Southern Plains region is principally located south of the Northern Plains region to the United States border and extending into western Saskatchewan.
Reserves of natural gas, NGLs and light and medium crude oil are contained in numerous productive horizons at depths up to 2,300 meters. This region is one of the more mature regions of the Western Canadian Sedimentary Basin and requires continual operational cost control through efficient utilization of existing facilities, flexible infrastructure design and consolidation of interests where appropriate.
The Southeast Saskatchewan area is located in the southeastern portion of the province extending into Manitoba and produces primarily light sour crude oil from multiple productive horizons found at depths up to 2,700 meters.

39 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Oil Sands Mining and Upgrading
Horizon: The Company owns a 1 00% working interest in its Horizon oil sands leases which are located about 70 kilometers north of Fort McMurray, Alberta. In 2021, the Company completed an acquisition of a 5% net carried interest on an existing Company oil sands lease.
The oil sands resource at Horizon O il Sands is found in the Cretaceous McMurray Formation, which is further subdivided into three informal members: lower, middle and upper. Most of Horizon’s oil sands resource is found within the lower and middle McMurray Formation at depths ranging from 50 to 100 meters below the surface.
Horizon Oil Sands, which is accessible by private road and private airstrip, includes surface oil sands mining, bitumen extraction, bitumen upgrading and associated infrastructure. Mining of the oil sands is done using conventional truck and shovel technology. The ore is then processed through extraction and froth treatment facilities to produce bitumen, which is upgraded on-site into SCO. The SCO is transported from the site by pipeline to the Edmonton area for distribution. Two on-site cogeneration plants with a combined design capacity of 180 megawatts provide power and steam for operations.
The Company received project sanction by the Board of Directors in February 2005, authorizing management to proceed with Phase 1 of Horizon with a design capacity of 110,000 bbl/d. First SCO production was achieved during 2009.
In 2014, the Company completed the Phase 2A coker plant tie-in, followed by the Phase 2B expansion in 2016. In 2017, the Company completed the Phase 3 expansion bringing total production capacity to approximately 250,000 bbl/d.
In 2018, the Company acquired the Joslyn oil sands project, adding to the Company's total oil sands mining and upgrading reserves. This incorporation of the Joslyn leases (now, Horizon South) to the mine plan has allowed mining to continue south of the previously existing Horizon leases with opportunity for further cost optimizations.
AOSP: In 2017, the Company acquired a combined direct and indirect 70% interest in AOSP which is an oil sands mining and upgrading joint venture located in Alberta, Canada. The Company operates AOSP’s mining and extraction assets which are located in the Athabasca region near Fort McMurray, Alberta, and include the Muskeg River and Jackpine mines. Shell operates the Scotford Upgrader, including the Quest project, which is located near Fort Saskatchewan, northeast of Edmonton, Alberta and utilizes LC FINING technology to efficiently hydrocrack residuum to high-quality fuel oils and transportation fuels.
Bitumen is produced from the oil sands deposits using conventional truck and shovel technology. The ore is then processed through extraction and froth treatment facilities to produce bitumen. Diluted bitumen blend from the Muskeg River and Jackpine mines is transported to the Scotford Upgrader on the third party owned Corridor Pipeline where the bitumen is upgraded into Premium Albian Synthetic crude oil, Albian Heavy Synthetic crude oil and Vacuum Gas Oil and, in certain circumstances, other heavy blends. Diluent is transported from the Scotford Upgrader back to the Muskeg River mine through the combined Corridor Pipeline transport system. A long term off-take agreement is in place with Shell to purchase Vacuum Gas Oil at market rates as well as agreements to sell volumes of Premium Albian Synthetic and Albian Heavy Synthetic from the Scotford Upgrader at market rates.
Gross production capacity of the combined AOSP mines is approximately 320,000 bbl/d of bitumen. Shell obtained the Joint Review Panel Approval along with other associated approvals in 2013 for a 100,000 bbl/d expan sion of the Jackpine Mine and in 2019 the remaining major application approvals were obtained.

Canadian Natural 2023 Annual Information Form | 40

Principal Documents Exhibits
United Kingdom North Sea
Through its wholly owned subsidiary, CNR International (U.K.) Limited, formerly Ranger Oil (U.K.) Limited, the Company has operated in the North Sea for over 40 years and has developed a significant database, extensive operating experience and an experie nced staff. In 2023, the Company produced from 8 crude oil fields.
The northerly fields are centered around the Ninian field where the Company has a 100% operated working interest. The central processing facility is connected to other fields including the Strathspey, Columba BD, Columba E and Lyell fields where the Company operates with working interests of 91.6% to 100%.
In the central portion of the North Sea, the Company holds a 100% operated working interest in the T-block (comprising the Tiffany, Toni and Thelma fields).
The Company receives tariff revenue from third parties for the processing of crude oil and natural gas through certain processing facilities.
The decommissioning activities at the Banff and Kyle fields commenced in the second quarter of 2020 with cessation of production occurring in June of 2020. The decommissioning activities are targeted to be substantially complete in 2024.
The Company commenced abandonment of the Ninian North Platform in 2017. Dismantling and disposal of the platform topsides was completed in 2021, and jacket removal and dismantling was completed in 2022. These decommissioning activities were substantially completed in 2023 with regulatory close out expected in 2024.
In 2022, the prevailing regulatory and economic conditions and increasingly challenging commercial outlook in the United Kingdom led the Company to assess the viability of its North Sea operations. Following a detailed review of its development plans, the Company determined that the Ninian, Columba, Lyell and Strathspey fields are no longer economic and de-booked associated crude oil and natural gas reserves as at Dece mber 31, 2022. Planning for the decommissioning and abandonment of these fields is underway with Ninian well plug and abandonment having commenced in the fourth quarter of 2023.

41 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Offshore Africa
Côte d’Ivoire
The Company owns interests in two licences offshore Côte d’Ivoire. The first is a 58.7% operated working interest in the Espoir field in Block CI-26 which is located in water depths ranging from 100 to 700 meters. Production from East Espoir commenced in 2002 and from West Espoir in 2006. Crude oil from the East and West Espoir fields is produced to a dedicated FPSO with the associated natural gas delivered onshore for local power generation through a subsea pipeline.
The second is a 57.6% operated working interest in the Baobab field, located in Block CI-40, which is eight kilometers south of the Espoir facilities and located in water depths ranging from 1,000 to 1,400 meters. Production from the Baobab field commenced in 2005. Crude oil from the Baobab field is produced to a dedicated FPSO with the associated natural gas delivered onshore via a subsea pipeline tied into the Espoir infrastructure.
South Africa
In 2012, the Company completed the conversion of its 100% owned oil sub-lease in respect of Block 11B/12B (the “Block”) off the southeast coast of South Africa into an exploration right for petroleum for this area. The Company currently has a 20% non-operated working interest in the Block, having divested a 50% interest in the exploration right in a farm-out transaction in 2013 and an additional 30% interest in two separate farm out transactions in 2018. In 2018, the operator re-entered the suspended Brulpadda exploration well on the Block and subsequently announced the discovery of natural gas and condensate from that prospect. In 2020, the operator completed the drilling and testing of the Luiperd exploratory well on the Block and subsequently announced the discovery of natural gas and condensate on that prospect. In 2022, the operator, on behalf of the exploration rights holders, submitted an application to the government to convert the expiring exploration right to a production right, and is currently preparing a development plan for the Block (identified as Production Right 013PR on the map above). The application review is progressing and final ministerial approval is anticipated in 2024. Additional cash payments from some partners will be due to the Company after the grant of a production right and establishment of commerciality.

Canadian Natural 2023 Annual Information Form | 42

Principal Documents Exhibits
Producing and Non-Producing Crude Oil and Natural Gas Wells
The following table summarizes the number of wells in which the Company has a working interest that were producing or mechanically capable of producing as of December 31, 2023.

Producing | Natural Gas Wells | Crude Oil Wells | Total Wells |
| Gross | Net | Gross | Net | Gross | Net |
Canada |  |  |  |  |  |  |
Alberta | 22,741 |  | 18,319.8 |  | 10,717 |  | 9,864.0 |  | 33,458 |  | 28,183.8 |  |
British Columbia | 2,047 |  | 1,899.3 |  | 171 |  | 159.0 |  | 2,218 |  | 2,058.3 |  |
Saskatchewan | 9,202 |  | 8,451.4 |  | 2,125 |  | 1,201.3 |  | 11,327 |  | 9,652.7 |  |
Manitoba | — |  | — |  | 144 |  | 125.1 |  | 144 |  | 125.1 |  |
Total Canada | 33,990 |  | 28,670.5 |  | 13,157 |  | 11,349.4 |  | 47,147 |  | 40,019.9 |  |
North Sea UK Sector | 1 |  | 1.0 |  | 45 |  | 44.5 |  | 46 |  | 45.5 |  |
Offshore Africa |  |  |  |  |  |  |
Côte d’Ivoire | — |  | — |  | 22 |  | 12.8 |  | 22 |  | 12.8 |  |
Total Company | 33,991 |  | 28,671.5 |  | 13,224 |  | 11,406.7 |  | 47,215 |  | 40,078.2 |  |

The following table summarizes the number of wells in which the Company has a working interest that were not producing or not mechanically capable of producing as of December 31, 2023.

Non-Producing | Natural Gas Wells | Crude Oil Wells | Total Wells
| Gross | Net | Gross | Net | Gross | Net
Canada |  |  |  |  |  |
Alberta | 9,166 |  | 7,672.5 |  | 12,758 |  | 11,607.5 |  | 21,924 |  | 19,280.0 |
British Columbia | 2,345 |  | 2,096.5 |  | 412 |  | 363.5 |  | 2,757 |  | 2,460.0 |
Saskatchewan | 1,142 |  | 1,069.7 |  | 3,366 |  | 2,739.4 |  | 4,508 |  | 3,809.1 |
Manitoba | — |  | — |  | 156 |  | 104.7 |  | 156 |  | 104.7 |
Northwest Territories | 86 |  | 13.3 |  | — |  | — |  | 86 |  | 13.3 |
Total Canada | 12,739 |  | 10,852.0 |  | 16,692 |  | 14,815.1 |  | 29,431 |  | 25,667.1 |
United States Louisiana | — |  | — |  | 2 |  | 0.4 |  | 2 |  | 0.4 |
North Sea UK Sector | 2 |  | 2.0 |  | 22 |  | 22.0 |  | 24 |  | 24.0 |
Offshore Africa |  |  |  |  |  |
Côte d’Ivoire | — |  | — |  | 18 |  | 10.4 |  | 18 |  | 10.4 |
Total Company | 12,741 |  | 10,854.0 |  | 16,734 |  | 14,847.9 |  | 29,475 |  | 25,701.9 |

43 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Properties With No Attributed Reserves
The following table summarizes the Company’s unproved property as of December 31, 2023.

Country (thousands of acres) | Gross | Net
Canada | 23,056 |  | 18,805 |
US | 1 |  | 1 |
North Sea UK Sector | 105 |  | 103 |
Côte d’Ivoire | 61 |  | 34 |
South Africa | 2,933 |  | 587 |
Total Company | 26,156 |  | 19,530 |

Where the Company holds interests in different formations under the same surface area pursuant to separate leases, the acreage for each lease is included in the gross and net amounts.
Canadian Natural has approximately 0.37 million net acres attributed to the North America properties which are currently expected to expire by December 31, 2024.
SIGNIFICANT FACTORS OR UNCERTAINTIES RELEVANT TO PROPERTIES WITH NO ATTRIBUTED RESERVES
The Company’s unproved property holdings are diverse and located in the North America and International regions. The land assets range from discovery areas where tenure to the property is held indefinitely by hydrocarbon test results or production to exploration areas in the early stages of evaluation. The Company continually reviews the economic viability and ranking of these unproved properties on the basis of product pricing, capital availability and allocation and level of infrastructure development in any specific area. From this process, some properties are scheduled for economic development activities while others are temporarily held inactive, sold, swapped or allowed to expire and relinquished back to the mineral rights owner.
FORWARD CONTRACTS
In the ordinary course of business, the Company has a number of delivery commitments to provide crude oil and natural gas under existing contracts and agreements. The Company has sufficient crude oil and natural gas reserves to meet these commitments.
2023 COSTS INCURRED IN CRUDE OIL, NATURAL GAS AND NGLs ACTIVITIES

($ millions) | North America | North Sea | Offshore Africa | Total
Property Acquisitions |  |  |  |
Proved | 0 |  | — |  | — |  | 0 |
Unproved | — |  | — |  | — |  | — |
Exploration | 43 |  | — |  | 3 |  | 46 |
Development | 5,039 |  | 558 |  | 187 |  | 5,784 |
| 5,082 |  | 558 |  | 190 |  | 5,830 |
Add: Net non-cash and other costs (1) | (418) |  | (525) |  | (18) |  | (961) |
Costs Incurred | 4,664 |  | 33 |  | 172 |  | 4,869 |

(1)Non-cash and other costs are comprised primarily of changes in ARO and other fair value adjustments.

Canadian Natural 2023 Annual Information Form | 44

Principal Documents Exhibits
Exploration and Development Activities
The following table summarizes the crude oil and natural gas drilling activities completed by the Company for the year ended December 31, 2023. Total success rate for 2023, excluding service and stratigraphic test wells, was 99%.

| Exploratory Wells | Development Wells
| Gross | Net | Gross | Net
Canada – Exploration and Production |  |  |  |
Crude Oil | 1 |  | 0.8 |  | 227 |  | 220.6 |
Natural Gas | 1 |  | 0.7 |  | 77 |  | 60.5 |
Dry | — |  | — |  | 2 |  | 1.6 |
Service | — |  | — |  | 51 |  | 50.0 |
Stratigraphic | — |  | — |  | 24 |  | 24.0 |
Total | 2 |  | 1.5 |  | 381 |  | 356.7 |
Canada – Oil Sands Mining and Upgrading |  |  |  |
Service | — |  | — |  | 12 |  | 10.5 |
Stratigraphic | — |  | — |  | 394 |  | 334.3 |
Total | — |  | — |  | 406 |  | 344.8 |
Total Canada | 2 |  | 1.5 |  | 787 |  | 701.5 |
Total International | — |  | — |  | — |  | — |
Company Total | 2 |  | 1.5 |  | 787 |  | 701.5 |

2024 ACTIVITY
Safe, reliable, effective and efficient operations will continue to be a focus of the Company in 2024. In December 2023, the Company released its 2024 capital budget(1) of approximately $5,420 million. In addition, the Company expects to spend approximately $635 million on abandonment and reclamation obligations in 2024. Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, to respond to price volatility, changes in project returns and the balancing of project risks and time horizons. In 2024, annual production is targeted to range between 1,330,000 BOE/d, and 1,380,000 BOE/d. The 2024 drilling budget is weighted towards longer cycle projects in the first half of the year, primarily thermal in situ, which is expected to drive production growth post-2024. In the second half of the year, the program will shift to being weighted towards shorter cycle development opportunities to align with incremental market egress.
The 2024 capital budget and production targets constitute forward-looking information. Refer to the "Advisory" section of this AIF for further details on forward-looking information.
(1)The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's annual MD&A for the year ended December 31, 2023, dated February 28, 2024 for more details on net capital expenditures.

45 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
PRODUCTION ESTIMATES
The following table summarizes the estimated 2024 company gross proved and probable daily production included in the estimates of proved reserves and probable reserves as of December 31, 2023 using forecast prices and costs.

| Light and Medium Crude Oil (bbl/d) | Primary Heavy Crude Oil (bbl/d) | Pelican Lake Heavy Crude Oil (bbl/d) | Bitumen (Thermal Oil) (bbl/d) | Synthetic Crude Oil (bbl/d) | Natural Gas (MMcf/d) | Natural Gas Liquids (bbl/d) | Barrels of Oil Equivalent (BOE/d)
TOTAL PROVED |  |  |  |  |  |  |  |
North America | 39,515 |  | 69,565 |  | 44,280 |  | 264,085 |  | 438,065 |  | 1,847 |  | 62,886 |  | 1,226,219 |
North Sea | 4,377 |  |  |  |  |  | 2 |  |  | 4,749 |
Offshore Africa | 13,382 |  |  |  |  |  | 11 |  |  | 15,134 |
Total Company | 57,274 |  | 69,565 |  | 44,280 |  | 264,085 |  | 438,065 |  | 1,860 |  | 62,886 |  | 1,246,103 |
TOTAL PROBABLE |  |  |  |  |  |  |  |
North America | 5,176 |  | 6,544 |  | 1,541 |  | — |  | 22,990 |  | 229 |  | 8,613 |  | 83,054 |
North Sea | 253 |  |  |  |  |  | — |  |  | 325 |
Offshore Africa | 635 |  |  |  |  |  | 1 |  |  | 769 |
Total Company | 6,063 |  | 6,544 |  | 1,541 |  | — |  | 22,990 |  | 230 |  | 8,613 |  | 84,147 |

Canadian Natural 2023 Annual Information Form | 46

Principal Documents Exhibits
Production History and Netbacks

| 2023
| Q1 | Q2 | Q3 | Q4 | Year Ended
North America Production and Netbacks by Product (1)
Light and Medium Crude Oil (2) |  |  |  |  |
Average daily production (before royalties) (bbl/d) | 48,954 |  | 47,494 |  | 47,544 |  | 48,116 |  | 48,024 |
Average daily sales volumes (before royalties) (bbl/d) | 48,965.9 |  | 47,491 |  | 47,565 |  | 48,145 |  | 48,038 |
Netbacks ($/bbl) |  |  |  |  |
Sales price (3) | 90.52 |  | 90.22 |  | 100.87 |  | 91.58 |  | 93.30 |
Transportation (4) | 3.37 |  | 4.22 |  | 4.45 |  | 4.16 |  | 4.05 |
Royalties (5) | 17.81 |  | 15.57 |  | 16.98 |  | 16.01 |  | 16.60 |
Production expenses (6) | 29.57 |  | 27.16 |  | 24.47 |  | 21.89 |  | 25.76 |
Netback | 39.77 |  | 43.27 |  | 54.97 |  | 49.52 |  | 46.89 |
Primary Heavy Crude Oil (2) |  |  |  |  |
Average daily production (before royalties) (bbl/d) | 77,690 |  | 76,498 |  | 76,377 |  | 80,095 |  | 77,668 |
Average daily sales volumes (before royalties) (bbl/d) | 78,779 |  | 75,673 |  | 75,460 |  | 81,330 |  | 77,811 |
Netbacks ($/bbl) |  |  |  |  |
Sales price (3) | 60.31 |  | 76.20 |  | 93.80 |  | 72.90 |  | 75.67 |
Transportation (4) | 4.36 |  | 5.08 |  | 4.82 |  | 4.77 |  | 4.75 |
Royalties (5) | 8.70 |  | 10.96 |  | 18.23 |  | 12.89 |  | 12.68 |
Production expenses (6) | 21.47 |  | 20.07 |  | 19.68 |  | 18.28 |  | 19.85 |
Netback | 25.78 |  | 40.09 |  | 51.07 |  | 36.96 |  | 38.39 |
Pelican Lake Heavy Crude Oil (2) |  |  |  |  |
Average daily production (before royalties) (bbl/d) | 48,244 |  | 47,151 |  | 46,897 |  | 46,046 |  | 47,078 |
Average daily sales volumes (before royalties) (bbl/d) | 48,307 |  | 46,297 |  | 46,544 |  | 46,609 |  | 46,934 |
Netbacks ($/bbl) |  |  |  |  |
Sales price (3) | 67.57 |  | 76.66 |  | 93.19 |  | 73.47 |  | 77.69 |
Transportation (4) | 4.56 |  | 4.69 |  | 4.04 |  | 4.11 |  | 4.35 |
Royalties (5) | 18.35 |  | 18.63 |  | 27.63 |  | 17.93 |  | 20.63 |
Production expenses (6) | 9.63 |  | 8.55 |  | 8.02 |  | 8.11 |  | 8.58 |
Netback | 35.03 |  | 44.79 |  | 53.50 |  | 43.32 |  | 44.13 |
Bitumen (Thermal Oil) (2) |  |  |  |  |
Average daily production (before royalties) (bbl/d) | 242,884 |  | 238,941 |  | 287,085 |  | 278,422 |  | 262,000 |
Average daily sales volumes (before royalties) (bbl/d) | 245,416 |  | 241,764 |  | 284,791 |  | 281,366 |  | 263,491 |
Netbacks ($/bbl) |  |  |  |  |
Sales price (3) | 48.60 |  | 66.51 |  | 89.50 |  | 62.64 |  | 67.62 |
Transportation (4) | 5.47 |  | 5.41 |  | 4.35 |  | 4.13 |  | 4.79 |
Royalties (5) | 7.70 |  | 10.67 |  | 18.67 |  | 11.16 |  | 12.30 |
Production expenses (6) | 15.94 |  | 14.59 |  | 11.47 |  | 11.31 |  | 13.17 |
Netback | 19.49 |  | 35.84 |  | 55.01 |  | 36.04 |  | 37.36 |
Natural Gas |  |  |  |  |
Average daily production (before royalties) (MMcf/d) (7) | 2,127 |  | 2,072 |  | 2,139 |  | 2,218 |  | 2,139 |
Netbacks ($/Mcf) |  |  |  |  |
Sales price (3) | 4.22 |  | 2.47 |  | 2.76 |  | 2.75 |  | 3.04 |
Transportation (4) | 0.57 |  | 0.58 |  | 0.56 |  | 0.54 |  | 0.56 |
Royalties (5) | 0.27 |  | 0.07 |  | 0.09 |  | 0.09 |  | 0.13 |
Production expenses (6) | 1.43 |  | 1.35 |  | 1.22 |  | 1.09 |  | 1.27 |
Netback | 1.95 |  | 0.47 |  | 0.89 |  | 1.03 |  | 1.08 |
Natural Gas Liquids (2) |  |  |  |  |
Average daily production (before royalties) (bbl/d) | 59,577 |  | 55,059 |  | 61,678 |  | 68,900 |  | 61,330 |
Average daily sales volumes (before royalties) (bbl/d) | 59,577 |  | 55,059 |  | 61,678 |  | 68,900 |  | 61,330 |
Netbacks ($/bbl) |  |  |  |  |
Sales price (3) | 59.08 |  | 49.05 |  | 49.87 |  | 53.93 |  | 53.04 |
Transportation (4) | 2.52 |  | 2.70 |  | 2.73 |  | 2.74 |  | 2.67 |
Royalties (5) | 8.84 |  | 6.92 |  | 6.36 |  | 5.45 |  | 6.82 |
Production expenses (6) | 9.62 |  | 10.16 |  | 8.56 |  | 7.42 |  | 8.85 |
Netback | 38.10 |  | 29.27 |  | 32.22 |  | 38.32 |  | 34.70 |

47 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits

| 2023
| Q1 | Q2 | Q3 | Q4 | Year Ended
North Sea Production and Netbacks by Product (1)
Light and Medium Crude Oil |  |  |  |  |
Average daily production (before royalties) (bbl/d) | 13,240 |  | 12,699 |  | 12,016 |  | 12,616 |  | 12,639 |
Average daily sales volumes (before royalties) (bbl/d) | 0 |  | 19,991 |  | 7,839 |  | 15,032 |  | 10,749 |
Netbacks ($/bbl) |  |  |  |  |
Sales price (3) | — |  | 106.39 |  | 108.22 |  | 118.50 |  | 110.99 |
Transportation (4) | — |  | 2.35 |  | 1.96 |  | 1.17 |  | 1.86 |
Royalties (5) | — |  | 0.36 |  | 0.42 |  | 0.24 |  | 0.33 |
Production expenses (6) | — |  | 81.32 |  | 83.44 |  | 92.28 |  | 85.57 |
Netback | — |  | 22.36 |  | 22.40 |  | 24.81 |  | 23.23 |
Natural Gas |  |  |  |  |
Average daily production (before royalties) (MMcf/d) (7) | 3 |  | 2 |  | 1 |  | 2 |  | 2 |
Netbacks ($/Mcf) |  |  |  |  |
Sales price (3) | 11.81 |  | 9.48 |  | 9.99 |  | 9.66 |  | 10.45 |
Transportation (4) | — |  | — |  | — |  | — |  | — |
Royalties (5) | — |  | — |  | — |  | — |  | — |
Production expenses (6) | 10.80 |  | 9.17 |  | 9.19 |  | 9.52 |  | 9.85 |
Netback | 1.01 |  | 0.31 |  | 0.80 |  | 0.14 |  | 0.60 |
Offshore Africa Production and Netbacks by Product (1)
Light and Medium Crude Oil |  |  |  |  |
Average daily production (before royalties) (bbl/d) | 14,091 |  | 13,821 |  | 12,703 |  | 13,213 |  | 13,452 |
Average daily sales volumes (before royalties) (bbl/d) | 10,393 |  | 18,603 |  | 12,769 |  | 17,705 |  | 14,882 |
Netbacks ($/bbl) |  |  |  |  |
Sales price (3) | 98.60 |  | 100.68 |  | 118.09 |  | 107.88 |  | 106.25 |
Transportation (4) | — |  | — |  | — |  | — |  | — |
Royalties (5) | 9.46 |  | 10.77 |  | 8.90 |  | 10.58 |  | 10.08 |
Production expenses (6) | 21.90 |  | 19.44 |  | 20.04 |  | 23.25 |  | 21.14 |
Netback | 67.24 |  | 70.47 |  | 89.15 |  | 74.05 |  | 75.03 |
Natural Gas |  |  |  |  |
Average daily production (before royalties) (MMcf/d) (7) | 9 |  | 11 |  | 11 |  | 11 |  | 10 |
Netbacks ($/Mcf) |  |  |  |  |
Sales price (3) | 14.28 |  | 13.71 |  | 12.44 |  | 12.51 |  | 13.19 |
Transportation (4) | 0.18 |  | 0.17 |  | 0.17 |  | 0.18 |  | 0.19 |
Royalties (5) | 0.69 |  | 0.65 |  | 0.59 |  | 0.59 |  | 0.62 |
Production expenses (6) | 7.35 |  | 4.17 |  | 7.21 |  | 8.65 |  | 6.83 |
Netback | 6.06 |  | 8.72 |  | 4.47 |  | 3.09 |  | 5.55 |
Total Exploration and Production |  |  |  |  |
Barrels of Oil Equivalent (BOE) (8) |  |  |  |  |
Average daily production (before royalties) (BOE/d) | 861,163 |  | 839,080 |  | 902,761 |  | 919,180 |  | 880,766 |
Average daily sales volumes (before royalties) (BOD/d) | 847,922 |  | 852,295 |  | 895,107 |  | 930,859 |  | 881,810 |
Netbacks ($/BOE) (1) |  |  |  |  |
Sales price (3) | 44.98 |  | 48.94 |  | 59.40 |  | 48.41 |  | 50.54 |
Transportation (4) | 4.03 |  | 4.11 |  | 3.78 |  | 3.61 |  | 3.88 |
Royalties (5) | 6.56 |  | 6.75 |  | 10.61 |  | 7.05 |  | 7.77 |
Production expenses (6) | 13.51 |  | 14.24 |  | 11.64 |  | 11.75 |  | 12.74 |
Netback | 20.88 |  | 23.84 |  | 33.37 |  | 26.00 |  | 26.15 |
Oil Sands Mining and Upgrading Production and Netback (1)
SCO |  |  |  |  |
Average daily production (before royalties) (bbl/d) (9) | 458,228 |  | 355,246 |  | 490,853 |  | 500,133 |  | 451,339 |
Average daily sales volumes (before royalties) (bbl/d) | 462,021 |  | 350,041 |  | 492,926 |  | 491,339 |  | 449,282 |
Netbacks ($/bbl) |  |  |  |  |
Sales price (3) (10) | 96.07 |  | 95.08 |  | 108.55 |  | 98.73 |  | 100.06 |
Transportation (4) | 1.52 |  | 2.03 |  | 2.18 |  | 1.85 |  | 1.89 |
Royalties (5) (11) | 10.04 |  | 13.58 |  | 21.90 |  | 11.57 |  | 14.43 |
Production expenses (6) | 25.06 |  | 31.28 |  | 22.12 |  | 20.96 |  | 24.32 |
Netback | 59.45 |  | 48.19 |  | 62.35 |  | 64.35 |  | 59.42 |

Canadian Natural 2023 Annual Information Form | 48

Principal Documents Exhibits
Notes to Production History and Netback Tables
(1)Netback is a non-GAAP financial measure that represents the net cash flows provided from core activities after the impact of all costs associated with bringing a product to market, on a per unit basis. The Company considers netback a key measure in evaluating its performance as it demonstrates the efficiency and profitability of the Company's activities. The netback calculations include the non-GAAP financial measures: realized price and transportation. Refer to the discussion of netbacks in the "Non-GAAP and Other Financial Measures" section of the Company's annual MD&A for the year ended December 31, 2023, dated February 28, 2024, for additional non-GAAP disclosure.
(2)Component of North America Exploration and Production crude oil and NGLs production and sales.
(3)Calculated as product sales, less blending expenses, divided by respective sales volumes.
(4)Calculated as transportation expense divided by respective sales volumes.
(5)Calculated as royalties divided by respective sales volumes.
(6)Calculated as production expense divided by respective sales volumes.
(7)Natural gas production volumes approximate sales volumes.
(8)Barrels of oil equivalent sales include total Exploration and Production crude oil, NGLs, and natural gas sales.
(9)Oil Sands Mining and Upgrading production is net of mined diesel produced and consumed at Horizon.
(10)SCO sales price is net of feedstock and blending costs.
(11)Royalty expense in the Oil Sands Mining and Upgrading segment is calculated based on bitumen royalties expensed during the period.
Selected Financial Information

($ millions, except per common share amounts) |  | 2023 |  | 2022
Product sales (1) |  | $ | 40,835 |  |  | $ | 49,530 |
Crude oil and NGLs |  | $ | 37,300 |  |  | $ | 43,009 |
Natural gas |  |  |  | $ | 2,575 |  |  | $ | 5,236 |
Net earnings |  | $ | 8,233 |  |  | $ | 10,937 |
Per common share |  | – basic |  | $ | 7.54 |  |  | $ | 9.64 |
|  | – diluted |  | $ | 7.47 |  |  | $ | 9.52 |
Adjusted net earnings from operations (2) |  | $ | 8,533 |  |  | $ | 12,863 |
Per common share |  | – basic (3) |  | $ | 7.82 |  |  | $ | 11.33 |
|  | – diluted (3) |  | $ | 7.74 |  |  | $ | 11.19 |
Cash flows from operating activities |  | $ | 12,353 |  |  | $ | 19,391 |
Adjusted funds flow (2) |  | $ | 15,274 |  |  | $ | 19,791 |
Per common share |  | – basic (3) |  | $ | 14.00 |  |  | $ | 17.44 |
|  | – diluted (3) |  | $ | 13.86 |  |  | $ | 17.22 |
Total assets |  | $ | 75,955 |  |  | $ | 76,142 |
Long-term debt, net (4) |  | $ | 9,922 |  |  | $ | 10,525 |
Cash flows used in investing activities |  | $ | 4,858 |  |  | $ | 4,987 |
Net capital expenditures (5) |  | $ | 4,909 |  |  | $ | 5,136 |
Abandonment expenditures, net (2) |  | $ | 509 |  |  | $ | 335 |

Notes to Selected Financial Information
(1)Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements for the years ended December 31, 2023 and December 31, 2022, dated February 28, 2024.
(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's annual MD&A for the year ended December 31, 2023, dated February 28, 2024.
(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's annual MD&A for the year ended December 31, 2023, dated February 28, 2024.
(4)Capital management measure. Refer to note 16 to the Company's audited consolidated financial statements for the years ended December 31, 2023 and December 31, 2022, dated February 28, 2024.
(5)Non-GAAP Financial Measure. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's annual MD&A for the year ended December 31, 2023, dated February 28, 2024.

49 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Dividend History
On January 17, 2001 the Board of Directors approved a dividend policy for the payment of regular quarterly dividends. Dividends have been paid in January, April, July and October of each year since April 2001. The dividend policy of the Company undergoes a periodic review by the Board of Directors and is subject to change at any time depending upon the earnings of the Company, its financial requirements and other factors existing at the time.
The following table shows the aggregate amount of the cash dividends declared per common share of the Company in each of its last three years ended December 31.

| 2023 | 2022(1) | 2021
Cash dividends declared per common share | $ | 3.70 |  | $ | 4.60 |  | $ | 2.00 |

(1) Includes a special cash dividend of $1.50 per common share, as discussed below.
On February 28, 2024, the Board of Directors increased the regular quarterly cash dividend declared per common share from $1.00 to $1.05 beginning with the dividend payable on April 5, 2024.
In 2023, Board of Directors approved two increases in the regular quarterly cash dividend. The first increase was approved on March 1, 2023 and increased the quarterly cash dividend declared per common share from $0.85 to $0.90, beginning with the dividend payable on April 5, 2023. The second increase was declared on November 1, 2023, and increased the regular quarterly cash dividend declared per common share to $1.00 beginning with the dividend payable on January 5, 2024.
In 2022, the Board of Directors approved two increases in the regular quarterly cash dividend and a special cash dividend of $1.50 per common share (payable on August 23, 2022) for a total dividend amount of $4.60 per common share. The first increase in the regular quarterly cash dividend was approved on March 2, 2022 and increased the quarterly cash dividend to $0.75 per common share, beginning with the dividend payable on April 5, 2022. The second increase was approved on November 3, 2022 and increased the quarterly cash dividend to $0.85 per common share, beginning with the dividend payable on January 5, 2023.
In 2021, the Board of Directors approved two increases in the quarterly cash dividend. The first increase in 2021 increased the quarterly cash dividend to $0.47 per common share, beginning with the dividend payable on April 5, 2021. The second increase in 2021 increased the quarterly cash dividend to $0.5875 beginning with the dividend payable on January 5, 2022.
Description of Capital Structure
COMMON SHARES
The Company is authorized to issue an unlimited number of common shares, without nominal or par value. Holders of common shares are entitled to one vote per share at a meeting of shareholders of Canadian Natural, to receive such dividends as declared by the Board of Directors on the common shares and to receive pro-rata the remaining property and assets of the Company upon its dissolution or winding-up, subject to any rights having priority over the common shares.
On February 28, 2024, the Company's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval and the Company having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company's Annual and Special Meeting of Shareholders to be held on May 2, 2024.
PREFERRED SHARES
The Company has no preferred shares outstanding. The Company is authorized to issue an unlimited number of preferred shares issuable in one or more series. The directors of the Company are authorized to determine, before the issue thereof, the number of shares in each series and to determine the designation, rights, privileges, restrictions and conditions attaching to the preferred shares of each series.
CREDIT RATINGS
The following information relating to the Company's credit ratings is provided as it relates to the Company's financing costs, liquidity and operations. Specifically, credit ratings affect the Company's ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current rating on the Company's debt by its rating agencies or a negative change to the Company's ratings outlook could adversely affect the Company's cost of financing and its access to sources of liquidity and capital. In addition, changes to credit ratings may affect the Company's ability to, and the associated costs of, entering into ordinary course derivative or hedging transactions and entering into and maintaining ordinary course contracts with customers and suppliers on acceptable terms.
Credit ratings accorded to the Company’s debt securities are not recommendations to purchase, hold or sell the debt securities inasmuch as such ratings do not comment on the current market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant, and if any such rating is so revised or withdrawn, the Company is under no obligation to update this AIF.

Canadian Natural 2023 Annual Information Form | 50

Principal Documents Exhibits

| Senior Unsecured Debt Securities | Commercial Paper | Outlook/Trend (1)
Moody’s Investors Service, Inc. (“Moody’s”) | Baa1 | P-2 | Stable
S&P Global Ratings (“S&P”) | BBB- | A-3 | Stable
DBRS Limited (“DBRS”) | A (low) | — | Stable

(1)Moody’s and S&P assign a rating outlook to Canadian Natural and not to individual long-term debt instruments.
Credit ratings are intended to provide investors with an independent opinion of the Company's ability to meet its financial obligations as they come due.
Moody’s credit ratings are on a long-term debt rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of Baa by Moody’s is assigned to obligations that are judged to be medium-grade and are subject to moderate credit risk. Such securities may possess certain speculative characteristics. Moody’s appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa in its corporate bond rating system. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates that the obligation ranks in the lower end of its generic rating category. A Moody’s rating outlook is an opinion regarding the likely rating direction over the medium term. A "Negative", "Positive" or "Developing" outlook indicates a higher likelihood of a rating change over the medium term. A "Stable" outlook indicates a low likelihood of a rating change over the medium term. Moody’s credit ratings on commercial paper are on a short-term debt rating scale that ranges from P-1 to NP, representing the range of such securities rated from highest to lowest quality. A rating of P-2 by Moody’s indicates a strong ability to repay short-term obligations.
S&P’s credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. According to the S&P rating system, debt securities rated BBB exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments on the obligation. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the rating categories. An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate term, typically six months to two years. A "Negative", "Positive" or "Developing" outlook indicates a higher likelihood of a rating change during that time period. A “Stable” outlook indicates a low likelihood of a rating change during that time period. In determining a rating outlook, consideration is given to any changes in the economic and/or fundamental business conditions, however, an outlook is not necessarily a precursor of a rating change or future CreditWatch action. S&P credit ratings on commercial paper are on a short-term debt rating scale that ranges from A-1 to D, representing the range of such securities rated from highest to lowest quality. A rating of A-3 by S&P indicates that the obligor exhibits adequate protection parameters; however, adverse economic conditions or changing circumstances are more likely to weaken the obligor's capacity to meet its financial conditions on obligations.
DBRS’ credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. According to the DBRS rating system, debt securities rated A are of good credit quality. The capacity for the payment of financial obligations is substantial, though may be vulnerable to future events but qualifying negative factors are considered manageable. All rating categories other than AAA and D also contain subcategories “(high)” and “(low)” which indicate the relative standing within such rating category. The absence of either a "(high)" or "(low)" designation indicates the rating is in the middle of the category. The rating trend is DBRS’ opinion regarding the outlook for the rating in question, with rating trends falling into one of three categories “Positive”, “Stable”, or “Negative”. The rating trend indicates the direction in which DBRS considers the rating may move if present circumstances continue, or in certain cases, unless challenges are addressed.
The credit ratings accorded to the Company's debt securities and commercial paper by the rating agencies are not recommendations to purchase, hold or sell the debt securities or commercial paper inasmuch as such ratings do not comment as to current market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant, and if any such rating is so revised or withdrawn, the Company is under no obligation to update this AIF.
The Company has made payments to Moody’s, S&P and DBRS in connection with the assignment of ratings to our long-term and short-term debt and will make payments to Moody’s, S&P and DBRS in connection with the confirmation of such ratings from time to time. The Company has not made any other payments to the listed credit rating organizations in the last two years.

51 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Market for Securities
The Company’s common shares are listed and posted for trading on the TSX and the NYSE under the symbol CNQ. Set forth below is the trading activity of the Company’s common shares on the TSX in 2023.

| 2023 Monthly Historical Trading on TSX
Month | High | Low | Close | Volume
January | $ | 82.89 |  | $ | 69.92 |  | $ | 81.67 |  | 92,974,226
February | $ | 82.00 |  | $ | 73.52 |  | $ | 77.11 |  | 82,835,413
March | $ | 82.16 |  | $ | 67.13 |  | $ | 74.79 |  | 208,969,240
April | $ | 83.18 |  | $ | 77.72 |  | $ | 82.56 |  | 105,316,828
May | $ | 82.95 |  | $ | 72.83 |  | $ | 73.13 |  | 84,167,020
June | $ | 76.90 |  | $ | 69.83 |  | $ | 74.48 |  | 183,548,362
July | $ | 81.25 |  | $ | 71.61 |  | $ | 80.19 |  | 109,144,199
August | $ | 87.97 |  | $ | 77.81 |  | $ | 87.42 |  | 128,410,137
September | $ | 90.70 |  | $ | 82.33 |  | $ | 87.84 |  | 237,808,299
October | $ | 92.40 |  | $ | 81.68 |  | $ | 88.06 |  | 110,582,812
November | $ | 93.44 |  | $ | 85.14 |  | $ | 90.61 |  | 143,093,466
December | $ | 92.76 |  | $ | 82.34 |  | $ | 86.81 |  | 210,205,281

On March 1, 2023, the Board of Directors passed a resolution authorizing the Company to file a Notice of Intention with the TSX to purchase, by way of a Normal Course Issuer Bid ("NCIB"), up to 92,298,006 common shares, being 10.0% of the public float (as determined in accordance with the rules of the TSX) as at February 28, 2023 (the "2023 NCIB").
For the year ended December 31, 2023, the Company purchased 40,050,000 common shares at a weighted average price of $82.86 per common share, which includes share repurchases for the period January 1, 2023 through March 10, 2 023 that were executed under its prior NCIB, which expired o n March 10, 2023. S ubsequent to year-end, up to and including March 12, 2024, the Company purchased 5,175,000 shares under the 2023 NCIB at a weighted average price of $87.95 per common share.
On February 28, 2024, the Board of Directors passed a resolution authorizin g the Company to file a Notice of Intention with the TSX to purchase up to 90,231,429 common shares (being 10.0% of the Company's public float as at February 29, 2024 as determined in accordance with the rules of the TSX) by way of NCIB commencing on March 13, 2024 and expiring on March 12, 2025. Any purchases will be made through the facilities of the TSX, alternative Canadian trading platforms, and the NYSE.

Canadian Natural 2023 Annual Information Form | 52

Principal Documents Exhibits
Directors and Executive Officers
The names, municipalities of residence, offices held with the Company and principal occupations of the Directors and Executive Officers of the Company for the five preceding years, are set forth below. Further detail on the Directors and Named Executive Officers are found in the Company’s Information Circular dated March 13, 2024 incorporated herein by reference.

Name | Position Presently Held | Principal Occupation During Past 5 Years
Catherine M. Best, FCPA, ICD.D Calgary, Alberta Canada | Director (1)(2) (age 70) | Corporate director. She has served continuously as a director of the Company since November 2003 and is currently serving on the board of directors of Superior Plus Corporation. She is also a member of the Board of The Wawanesa Mutual Insurance Company and the Calgary Stampede Foundation.
M. Elizabeth Cannon, Ph.D., O.C. Calgary, Alberta Canada | Director (4)(5) (age 61) | Corporate director. She is currently President Emerita at the University of Calgary, having previously served at the University of Calgary as Dean of the Schulich School of Engineering from 2006-2010, and then as President and Vice Chancellor from 2010-2018. She was appointed as a director of the Company on November 5, 2019.
N. Murray Edwards, O.C. St. Moritz, Switzerland | Executive Chair and Director (age 64) | Corporate director and investor. He has served continuously as a director of the Company since September 1988. Currently, he is Chairman and serving on the board of directors of Ensign Energy Services Inc. and Magellan Aerospace Corporation.
Christopher L. Fong Calgary, Alberta Canada | Director (3)(5) (age 74) | Corporate director. He has served continuously as a director of the Company since November 2010. He is currently serving on the board of directors of Computer Modelling Group Ltd.
Ambassador Gordon D. Giffin Sarasota, Florida U.S.A. | Director (1)(4) (age 74) | Partner and Global Vice Chair emeritus, Dentons US LLP (law firm); prior thereto Senior Partner, McKenna Long & Aldridge LLP (law firm) from May 2001 until its merger with Dentons in 2015. He has served continuously as a director of the Company since May 2002. He is also currently serving on the board of trustees of the Carter Presidential Center.
Wilfred A. Gobert Calgary, Alberta Canada | Director (1)(2)(4) (age 76) | Independent businessman. He has served continuously as a director since November 2010. He is currently serving on the board of directors of Paramount Resources Ltd.
Christine M. Healy Montreal, Quebec Canada | Director(1)(4) (age 52) | Corporate director and President of AMEA (Asia, Middle East and Australia) of AtkinsRealis (EPC company). Prior thereto, Senior Vice President, Carbon Neutrality and Continental Europe for TotalEnergies from 2021 to 2023. From 2018 to 2020, Country Chair, President and CEO of Total E&P Canada. Prior to her tenure with TotalEnergies, Ms. Healy was Chief Strategy Officer and General Counsel of Maersk Oil and Gas. She was appointed as a director of the Company effective February 27, 2024.

53 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits

Name | Position Presently Held | Principal Occupation During Past 5 Years
Steve W. Laut Calgary, Alberta Canada | Director (3)(5) (age 66) | Corporate director. He was an officer of the Company until May 5, 2020. He has served continuously as a director of the Company since August 2006.
Honourable Frank J. McKenna P.C., O.C., O.N.B., K.C. Cap Pelé, New Brunswick Canada | Director (2)(4) (age 76) | Deputy Chair, TD Bank Group (bank). He has served continuously as a director of the Company since August 2006. Currently serving on the board of directors of Brookfield Asset Management Inc.
David A. Tuer Calgary, Alberta Canada | Director (1)(5) (age 74) | Corporate director. Prior thereto, Chairman, Optiom Inc. (private insurance company) since 2015; prior thereto, from 2010 to 2015, the Vice-Chairman and Chief Executive Officer of Teine Energy Ltd. (private oil and gas exploration company) and served as Vice-Chairman and Chief Executive Officer of Marble Point Energy Ltd., the predecessor to Teine Energy Ltd. from 2008 to 2010. He has served continuously as a director of the Company since May 2002.
Scott G. Stauth Calgary, Alberta Canada | President and Director(3)(6)(7) (age 58) | Officer of the Company. He was appointed to the Board of Directors on February 27, 2024.
Annette M. Verschuren, O.C. Toronto, Ontario Canada | Director (2)(3) (age 67) | Chair and Chief Executive Officer of NRStor Inc., an energy storage project developer of energy storage technologies. She has served as a director of the Corporation continuously since November 2014. She currently serves as Chancellor of Cape Breton University and as a director of Liberty Mutual Insurance Group and a board member of numerous non-profit organizations. Currently serving on the board of directors of Air Canada and Saputo Inc.
Tim S. McKay Calgary, Alberta Canada | Vice Chairman (6) (age 62) | Officer of the Company. He served continuously as President and as a director of the Company from February 2018 to February 2024.
Troy J.P. Andersen Calgary, Alberta Canada | Senior Vice-President, Canadian Conventional Field Operations (age 45) | Officer of the Company.
Brenda G. Balog Heritage Pointe, Alberta Canada | Vice-President, Legal and General Counsel (age 55) | Officer of the Company since April 2023. Prior thereto, Manager, Legal, Corporate Operations since 2011.
Calvin J. Bast Calgary, Alberta Canada | Senior Vice-President, Production (age 49) | Officer of the Company.

Canadian Natural 2023 Annual Information Form | 54

Principal Documents Exhibits

Name | Position Presently Held | Principal Occupation During Past 5 Years
Victor C. Darel Calgary, Alberta Canada | Senior Vice-President, Finance and Principal Accounting Officer (age 42) | Officer of the Company since May 2021. Prior thereto, Manager, Financial Reporting from April 2017 to October 2019, Controller, Corporate Reporting from November 2019 to May 2021, and most recently Vice-President, Finance and Principal Accounting Officer from May 2021 to June 2023.
Jay E. Froc Calgary, Alberta Canada | Chief Operating Officer, Oil Sands Mining and Upgrading (age 58) | Officer of the Company.
Dwayne F. Giggs Calgary, Alberta Canada | Senior Vice-President, Exploration (age 47) | Officer of the Company since April 2021. Prior thereto, Exploration Manager from January 2017 to April 2021, and most recently Vice President - Exploration West from April 2021 to November 2021.
Dean W. Halewich Calgary, Alberta Canada | Senior Vice-President, Safety, Risk Management and Innovation (age 56) | Officer of the Company.
Ronald K. Laing Calgary, Alberta Canada | Senior Vice-President, Corporate Development and Land (age 54) | Officer of the Company.
Devin C. Lowe Calgary, Alberta Canada | Senior Vice-President, Exploitation (age 50) | Officer of the Company.
Erin L. Lunn Calgary, Alberta Canada | Vice-President, Land (age 49) | Officer of the Company since February 2022. Prior thereto Land Manager, Negotiations from July 2016 to February 2022.
Mark A. Overwater Calgary, Alberta Canada | Vice-President, Marketing (age 56) | Officer of the Company since February 2023. Prior thereto Director, Crude Oil Marketing since May 2017.
Kyle G. Pisio Calgary, Alberta Canada | Vice-President, Drilling, Completions and Asset Retirement (age 42) | Officer of the Company since June 2021. Prior thereto Manager, Completions Engineering from July 2016 to June 2021.
Warren P. Raczynski Calgary, Alberta Canada | Senior Vice-President, Thermal (age 51) | Officer of the Company since June 2019. Prior thereto, Manager, Exploitation until June 2019, and most recently Vice-President, Exploitation, Jackfish from June 2019 to April 2022.

55 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits

Name | Position Presently Held | Principal Occupation During Past 5 Years
Roy D. Roth Calgary, Alberta Canada | Vice-President, Facilities and Pipelines (age 50) | Officer of the Company.
Kara L. Slemko Calgary, Alberta Canada | Vice-President, Corporate Development and Commercial Operations (age 54) | Officer of the Company.
Mark A. Stainthorpe Calgary, Alberta Canada | Chief Financial Officer (age 46) | Officer of the Company.
Trevor T. Wagil Sturgeon County, Alberta Canada | Senior Vice-President, Oil Sands Mining (age 39) | Officer of the Company since 2020. Prior thereto Director, Bitumen Production, Horizon from January 2018 to January 2020, and most recently, Vice-President, Horizon Bitumen Production from January 2020 to January 2024.
Robin S. Zabek Calgary, Alberta Canada | Chief Operating Officer, Exploration and Production (age 52) | Officer of the Company.

(1)Member of the Audit Committee.
(2)Member of the Compensation Committee.
(3)Member of the Health, Safety, Asset Integrity and Environmental Committee.
(4)Member of the Nominating, Governance and Risk Committee.
(5)Member of the Reserves Committee.
(6)Mr. Tim S. McKay stepped down as President effective February 28, 2024 and assumed the role of Vice-Chairman to support management transition until his retirement. Mr. McKay resigned as a Director of the Company effective February 27, 2024.
(7)Mr. Scott G. Stauth was appointed President of the Company effective February 28, 2024.
Al l directors stand for electi on at each Annual Meeting of the Company's Shareholders. With the exception of Ms. Christine M. Healy and Mr. Scott G. Stauth, all of the current directors were elected to the Board at the last Annual Meeting of the Company's Shareholders held on May 4, 2023. Mr. Stauth and Ms. Healy were appointed to the Company's Board of Directors on February 27, 2024.
As of the date hereof, 10 of the 12 directors are independent. The two management directors are Mr. N. Murray Edwards, and Mr. Scott G. Stauth.
As at December 31, 2023, the directors and executive officers of the Company, as a group, beneficially owned or controlled or directed, directly or indirectly, in the aggregate, approximately 24 million common shares (approximately 2%) of the total outstanding common shares of 1,072,408,000 (approximately 3% after the exercise of options held by them pursuant to the Company’s stock option plan).
There are potential conflicts of interest to which the directors and officers of the Company may become subject in connection with the operations of the Company. Some of the directors and officers have been and will continue to be engaged in the identification and evaluation of businesses and assets with a view to potential acquisition of interests on their own behalf and on behalf of other corporations. Situations may arise where the directors and officers will be in direct competition with the Company. Conflicts, if any, will be subject to the procedures and remedies under the Business Corporations Act (Alberta).

Canadian Natural 2023 Annual Information Form | 56

Principal Documents Exhibits
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
From time to time, the Company is the subject of litigation arising out of the Company's normal course of operations. Damages claimed under such litigation may be material and the outcome of such litigation may materially impact the Company's financial condition or results of operations. While the Company assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself in such litigation. There are currently no legal proceedings to which the Company is or was a party, or that any of its property is or was the subject of, which would be expected to have a material impact on the Company's financial condition and the Company is not aware of any such legal proceedings that are contemplated.
During the year ended December 31, 2023, there were no penalties or sanctions imposed against the Company by a court of competent jurisdiction or other regulatory body relating to securities legislation or by a securities regulatory authority and the Company has not entered into any settlement agreements before a court of competent jurisdiction or other regulatory body relating to securities legislation or with a securities regulatory authority.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
No director, executive officer or principal shareholder of the Company, or associate or affiliate of those persons, has any material interest, direct or indirect, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect the Company.
TRANSFER AGENTS AND REGISTRAR
The Company’s transfer agent and registrar for its common shares is Computershare Trust Company of Canada in the cities of Calgary and Toronto and Computershare Investor Services LLC in the city of New York. The registers for transfers of the Company’s common shares are maintained by Computershare Trust Company of Canada.
MATERIAL CONTRACTS
During the most recently completed financial year, the Company did not enter into any contracts, nor are there any contracts still in effect, that are material to the Company’s business, other than contracts entered into in the ordinary course of business.
INTERESTS OF EXPERTS
The Company’s independent auditors are PricewaterhouseCoopers LLP, Chartered Professional Accountants, who have issued an independent auditor’s report dated February 28, 2024 in respect of the Company’s consolidated financial statements as at December 31, 2023 and December 31, 2022 and for each of the three years in the period ended December 31, 2023 and the Company’s internal control over financial reporting as at December 31, 2023. PricewaterhouseCoopers LLP has advised that they are independent with respect to the Company within the meaning of the Rules of Professional Conduct with Guidance of the Chartered Professional Accountants of Alberta and the rules of the US Securities and Exchange Commission.
Based on information provided by the relevant persons or companies, there are beneficial interests, direct or indirect, in less than 1% of the Company’s securities or property or securities or property of our associates or affiliates held by Sproule Associates Limited, Sproule International Limited or GLJ Ltd., or any partners, employees or consultants of such independent reserves evaluators who participated in and who were in a position to directly influence the preparation of the relevant report, or any such person who, at the time of the preparation of the report was in a position to directly influence the outcome of the preparation of the report.
AUDIT COMMITTEE INFORMATION
Audit Committee Members
The Audit Committee of the Board of Directors is comprised of Ms. C. M. Best, Chair, Messrs. G. D. Giffin, W.A. Gobert and D. A. Tuer, and Ms. C.M. Healy, eac h of whom is independent and financially literate as those terms are defined under Canadian securities regulations, National Instrument 52-110 and the NYSE listing standards as they pertain to audit committees of listed issuers. The education and experience of each member of the Audit Committee relevant to their responsibilities as an Audit Committee member is described below.
Ms. C. M. Best is a chartered accountant with over 20 years’ experience as a staff member and partner of an international public accounting firm. During her tenure, she was responsible for direct oversight and supervision of a large staff of auditors conducting audits of the financial reporting of significant publicly traded entities, many of which were oil and gas companies. This oversight and supervision required Ms. C. M. Best to maintain a current understanding of generally accepted accounting principles, and be able to assess their application in each of her clients. It also required an understanding of internal controls and financial reporting processes and procedures. Ms. C. M. Best, who is chair of the Audit Committee, qualifies as an “audit committee financial expert” under the rules issued by the SEC pursuant to the requirements of the Sarbanes-Oxley Act of 2002.

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Principal Documents Exhibits
Ambassador G. D. Giffin’s education and experience relevant to the performance of his responsibilities as an audit committee member is derived from a law practice of over thirty years, involving complex accounting and audit-related issues associated with complicated commercial transactions and disputes. He has developed extensive practical experience and an understanding of internal controls and procedures for financial reporting from his service on audit committees for several publicly traded issuers and the continued pursuit of extensive professional reading and study on related subjects.
Mr. W.A. Gobert holds an MBA (Finance) degree from McMaster University as well as a Bachelor of Science (Honours) degree from the University of Windsor and holds a Chartered Financial Analyst (CFA) designation. Mr. Gobert was Vice Chair of Peters & Co. Limited, an independent, fully integrated investment dealer specializing in providing comprehensive investment research, and acting as an active underwriter and financial advisor specializing in the Canadian energy sector. During his 27 year career with Peters & Co. Limited, Mr. Gobert developed expertise in connection with the review, analysis and evaluation of financial statements that presented a variety of complex accounting issues and subsequently supervised and oversaw individuals directly engaged in the review, analysis and evaluation of similarly complex financial disclosure. As a result, Mr. Gobert developed an understanding of generally accepted accounting principles, financial statements, internal controls and financial reporting. Mr. Gobert qualifies as an "audit committee financial expert" under the rules issued by the SEC pursuant to the requirements of the Sarbanes-Oxley Act of 2002.
Mr. D. A. Tuer's education and experience relevant to the performance of his responsibilities as an audit committee member is derived from professional training and a business career as a chief executive officer in a large publicly traded company which provided experience in analyzing and evaluating financial statements and supervising persons engaged in the preparation, analysis and evaluation of financial statements of publicly traded companies. He has gained an understanding of internal controls and procedures for financial reporting through oversight of those functions, and the understanding of audit committee functions through his years of chief executive involvement.
Ms. C.M. Healy holds a B.A. (Hon.), Economics from Memorial University and a Juris Doctor from Osgoode Hall Law School. Ms. Healy's education and experience relevant to the performance of her responsibilities as an audit committee member is derived from her professional training and a 26 year legal/business career in the energy industry in both the public and private sector, which involved complex accounting and audit-related issues associated with strategic development of business assets, portfolio management, mergers and acquisitions and complex commercial issues and transactions associated with resource management and development both domestically and internationally. She gained an understanding of audit committee functions and internal controls for financial reporting through her executive oversight of those functions in various chief executive and senior management roles. Ms. Healy was also Vice Chair of the Board and Chair of the Audit and Risk Committee for Lester B. Pearson United World College of the Pacific.
Auditor Service Fees
The Audit Committee of the Board of Directors in 2023 approved specified audit and non-audit services to be performed by PricewaterhouseCoopers LLP (“PwC”). The services provided include: (i) the annual audit of the Company's consolidated financial statements and internal controls over financial reporting, reviews of the Company's quarterly unaudited consolidated financial statements, audits of certain of the Company's subsidiary companies' annual financial statements as well as other audit services provided in connection with statutory and regulatory filings as set out in "Audit fees" in the table below; (ii) audit related services including pension assets, Crown Royalty Statements, and GHG emissions; (iii) tax services related to expatriate personal tax and compliance and other corporate tax return matters as set out in "Tax fees" in the table below; and (iv) non-audit services related to expatriate visa application assistance and to accessing resource materials through PwC’s accounting literature library as set out in "All other fees" in the table below.

Auditor service (000’s) | 2023 | 2022
Audit fees | $ | 2,465 |  | $ | 2,327 |
Audit related fees (1) | 1,421 |  | 698 |
Tax fees | 400 |  | 402 |
All other fees | 6 |  | 9 |
Total | $ | 4,292 |  | $ | 3,436 |

(1) Audit related fees in 2023 included an increase of $0.7 million due to 2022 GHG emissions and verification procedures being performed in fiscal year 2023 as well as accelerating the timing of the 2023 procedures.
The Charter of the Audit Committee of the Company is attached as Schedule “C” to this AIF.

Canadian Natural 2023 Annual Information Form | 58

Principal Documents Exhibits
ADDITIONAL INFORMATION
Additional information relating to the Company can be found on the SEDAR+ website at www.sedarplus.ca and on EDGAR at www.sec.gov.
Additional information including Directors' and Executive Officers' remuneration and indebtedness, Director nominees standing for re-election, principal holders of the Company's securities, options to purchase the Company's securities and the interest of insiders in material transactions is contained in the Company's Notice of Annual Meeting and Information Circular dated March 13, 2024 in connection with the Annual and Special Meeting of Shareholders of Canadian Natural to be held on May 2, 2024 which information is incorporated herein by reference. Additional financial information and discussion of the affairs of the Co mpany and the business environment in which the Company operates is provided in the Company's MD&A, comparative Consolidated Financial Statements and Supplementary Oil & Gas Information for the most recently completed fiscal year ended December 31, 2023 respectively, as set forth in th e 2023 Annual Report to the Shareholders, which information is incorporated herein by reference.
For additional copies of this AIF, please contact:
Corporate Secretary of the Corporation at:
2100, 855 - 2nd Street S.W.
Calgary, Alberta T2P 4J8

59 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
SCHEDULE “A”
FORM 51-101F2
REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
Report on Reserves Data
To the Board of Directors of Canadian Natural Resources Limited (the “Company”):
1.We have evaluated and reviewed the Company’s North America, United Kingdom and Offshore Africa petroleum and natural gas reserves data as at December 31, 2023. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2023, estimated using forecast prices and costs.
2.The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation and review.
3.We carried out our evaluation and review in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”) maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
4.Those standards require that we plan and perform an evaluation and review to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation and review also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
5.The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to total proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated and reviewed for the year ended December 31, 2023, and identifies the respective portions thereof that we have evaluated and reviewed and reported on to the Company’s management and board of directors:

Independent Qualified Reserves Evaluator or Auditor | Effective Date of Evaluation/Review Report | Location of Reserves (Country or Foreign Geographic Area) | Net Present Value of Future Net Revenue (Before Income Taxes, 10% Discount Rate) ($ millions)
Audited | Evaluated | Reviewed | Total
Sproule Associates Limited | December 31, 2023 | Canada and USA | — | 80,178 | 10,267 | 90,445
Sproule International Limited | December 31, 2023 | United Kingdom and Offshore Africa | — | 942 | — | 942
Total |  |  | — | 81,120 | 10,267 | 91,387

6.In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
7.We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports as of December 31, 2023.
8.Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

Canadian Natural 2023 Annual Information Form | 60

Principal Documents Exhibits
Executed as to our report referred to above:

Sproule Associates Limited Calgary, Alberta, Canada, February 28, 2024 | Sproule International Limited Calgary, Alberta, Canada, February 28, 2024
Original Signed By SIGNED "GARY R. FINNIS" "Professional Stamp" Gary R. Finnis, P.Eng. Senior Manager, Engineering Date: February 28, 2024 APEGA ID 62965 | Original Signed By SIGNED "ILIA CHAIKINE" Ilia Chaikine Petroleum Engineer DATE: February 28, 2024 APEGA ID 138300
| Original Signed By SIGNED "ALEXEY ROMANOV" Alexey Romanov, Ph.D., P.Geo Senior Geoscientist February 28, 2024 RM APEGA ID 112313
Sproule Associates Limited APEGA Permit #00417 | Sproule International Limited APEGA Permit #06151
Original Signed By SIGNED "STEVEN GOLKO" Steven Golko, P.Eng. Managing Director, Reservoir Services Date: February 28, 2024 RM APEGA ID 80169 | Original Signed By SIGNED "MEGHAN KLEIN" "Professional Stamp" Meghan Klein, P.Eng. Senior Manager, Engineering Date: February 28, 2024 RM APEGA ID 84981

61 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
FORM 51-101F2
REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
Report on Reserves Data
To the Board of Directors of Canadian Natural Resources Limited (the “Company”):
1.We have evaluated the Company’s Canadian Oil Sands Mining and Upgrading reserves data as at December 31, 2023. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2023, estimated using forecast prices and costs.
2.The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
3.We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”) maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
4.Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
5.The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to total proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2023, and identifies the respective portions thereof that we have evaluated and reported on to the Company’s management and board of directors:

Independent Qualified Reserves Evaluator or Auditor | Effective Date of Evaluation/Review Report | Location of Reserves (Country or Foreign Geographic Area) | Net Present Value of Future Net Revenue (Before Income Taxes, 10% Discount Rate) ($ millions)
Audited | Evaluated | Reviewed | Total
GLJ Ltd. | December 31, 2023 | Canada | — | 95,067 | — | 95,067
Total |  |  | — | 95,067 | — | 95,067

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

GLJ Ltd., Calgary, Alberta, Canada, February 28, 2024 |
"Original Signed By" Tracy Bellingham, P.Eng. Vice President |

Canadian Natural 2023 Annual Information Form | 62

Principal Documents Exhibits
SCHEDULE “B”
FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
Report of Management and Directors on Reserves Data and Other Information
Management of Canadian Natural Resources Limited (the “Company”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.
Independent qualified reserves evaluators have evaluated and reviewed the Company’s reserves data. The report of the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.
The Reserves Committee of the Board of Directors of the Company has:
(a)reviewed the Company’s procedures for providing information to the independent qualified reserves evaluators;
(b)met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and
(c)reviewed the reserves data with management and the independent qualified reserves evaluators.
The Reserves Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved:
(a)the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
(b)the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators on the reserves data; and
(c)the content and filing of this report.

63 | Canadian Natural 2023 Annual Information Form

Principal Documents Exhibits
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
Original Signed By
SIGNED "SCOTT G. STAUTH"
Scott G. Stauth
President
Original Signed By
SIGNED "MARK A. STAINTHORPE"
Mark A. Stainthorpe
Chief Financial Officer
Original Signed By
SIGNED "DAVID A. TUER"
David A. Tuer
Independent Director and Chair of the Reserves Committee
Original Signed By
SIGNED "CATHERINE M. BEST"
Catherine M. Best
Independent Director and Chair of the Audit Committee
Dated thi s 28th d ay of February, 2024

Canadian Natural 2023 Annual Information Form | 64

Principal Documents Exhibits
SCHEDULE “C”
CANADIAN NATURAL RESOURCES LIMITED
(the “Corporation”)
Charter of the Audit Committee of the Board of Directors
I Audit Committee Purpose
The Audit Committee is appointed by the Board of Directors (the “Board”) to assist the Board in fulfilling its responsibility for the stewardship of the Corporation in overseeing the business and affairs of the Corporation. Although the Audit Committee has the powers and responsibilities set forth in this Charter, the role of the Audit Committee is oversight. The Audit Committee’s primary duties and responsibilities are to:
1.ensure that the Corporation’s management implemented an effective system of internal controls over financial reporting;
2.monitor and oversee the integrity of the Corporation’s financial statements, financial reporting processes and systems of internal controls regarding financial, accounting and compliance with regulatory and statutory requirements as they relate to financial statements, taxation matters and disclosure of material facts;
3.consider and recommend to the Board, jointly with the Health, Safety, Asset Integrity and Environmental Committee of the Board, the accounting firm to be retained by the Corporation to complete an independent assurance review of the Corporation's GHG emissions reporting and establish the fees and other compensation to be paid in respect thereof;
4.select and recommend for appointment by the shareholders, the Corporation’s independent auditors, pre-approve all audit and non-audit services to be provided to the Corporation by the Corporation’s independent auditors consistent with all applicable laws, and establish the fees and other compensation to be paid to the independent auditors;
5.monitor the independence, qualifications and performance of the Corporation’s independent auditors and oversee the audit and review of the Corporation’s financial statements;
6.monitor the performance of the Corporation's internal audit function, internal control of financial reporting programs, Sarbanes-Oxley Compliance program as well as the cybersecurity measures implemented in response to the Corporation's assessment of Cyber risk;
7.establish procedures for the receipt, retention, response to and treatment of complaints, including confidential, anonymous submissions by the Corporation’s employees, regarding accounting, internal controls or auditing matters; and
8.provide an avenue of communication among the independent auditors, management, the internal auditing function and the Board.
II Audit Committee Composition, Procedures and Organization
1.The Audit Committee shall consist of at least three (3) directors as determined by the Board, each of whom shall be independent, non-executive directors, free from any relationship that would interfere with the exercise of his or her independent judgment. Audit Committee members shall meet the independence and experience requirements of the regulatory bodies to which the Corporation is subject to. All members of the Audit Committee shall have a basic understanding of finance and accounting and be able to read and understand fundamental financial statements at the time of their appointment to the Audit Committee. At least one member of the Audit Committee shall have accounting or related financial management expertise and qualify as a “financial expert” or similar designation in accordance with the requirements of the regulatory bodies to which the Corporation may be subject to.
2.The Board at its organizational meeting held in conjunction with each annual general meeting of the shareholders shall appoint the members of the Audit Committee for the ensuing year. The Board may at any time remove or replace any member of the Audit Committee and may fill any vacancy in the Audit Committee.
3.The Board shall appoint a member of the Audit Committee as chair of the Audit Committee. If an Audit Committee Chair is not designated by the Board, or is not present at a meeting of the Audit Committee, the members of the Audit Committee may designate a chair by majority vote of the Audit Committee membership.
4.The Secretary or the Assistant Secretary of the Corporation shall be secretary of the Audit Committee unless the Audit Committee appoints a secretary of the Audit Committee.
5.The quorum for meetings shall be one half (or where one half of the members of the Audit Committee is not a whole number, the whole number which is closest to and less than one half) of the members of the Audit Committee subject to a minimum of two members of the Audit Committee present in person or by telephone or other telecommunications device that permits all persons participating in the meeting to speak and to hear each other.
6.Meetings of the Audit Committee shall be conducted as follows:
(a)the Audit Committee shall meet at least four (4) times annually at such times and at such locations as may be requested by the Chair of the Audit Committee;

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(b)the Audit Committee shall meet privately in executive sessions at each meeting with management, the manager of internal auditing, the independent auditors, and as a committee to discuss any matters that the Audit Committee or each of these groups believe should be discussed.
7.The independent auditors and internal auditors shall have a direct line of communication to the Audit Committee through its chair and may bypass management if deemed necessary. Any employee may bring before the Audit Committee directly and may bypass management if deemed necessary any matter involving questionable, illegal or improper financial practices or transactions.
III Audit Committee Duties and Responsibilities
1.The overall duties and responsibilities of the Audit Committee shall be as follows:
(a)to assist the Board in the discharge of its responsibilities relating to the Corporation’s accounting principles, reporting practices and internal controls and its approval of the Corporation’s annual and quarterly consolidated financial statements;
(b)to establish and maintain a direct line of communication with the Corporation’s internal auditors and independent auditors and assess their performance;
(c)to ensure that the management of the Corporation has implemented and is maintaining an effective system of internal controls over financial reporting;
(d)to report regularly to the Board on the fulfillment of its duties and responsibilities; and,
(e)to review annually the Audit Committee Charter and recommend any changes to the Nominating, Governance and Risk Committee for approval by the Board.
2.The duties and responsibilities of the Audit Committee as they relate to the independent auditors shall be as follows:
(a)to select and recommend to the Board of Directors for appointment by the shareholders, the Corporation’s independent auditors, review the independence and monitor the performance of the independent auditors and approve any discharge of auditors when circumstances warrant;
(b)to approve the fees and other significant compensation to be paid to the independent auditors, scope and timing of the audit and other related services rendered by the independent auditors;
(c)to review and discuss with management and the independent auditors prior to the annual audit the independent auditor’s annual audit plan, including scope, staffing, locations and reliance upon management and internal audit department and oversee the audit of the Corporation’s financial statements;
(d)to pre-approve all proposed non-audit services to be provided by the independent auditors except those non-audit services prohibited by legislation;
(e)on an annual basis, obtain and review a report by the independent auditors describing (i) the independent auditor’s internal quality control procedures; (ii) any material issues raised by the most recent quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities within the preceding five years respecting one or more independent audits carried out by the firm; and, (iii) any steps taken to address any such issues arising from the review, inquiry or investigation, and, receive a written statement from the independent auditors outlining all significant relationships they have with the Corporation that could impair the auditor’s independence. The Corporation’s independent auditors may not be engaged to perform prohibited activities under the Sarbanes-Oxley Act of 2002 or the rules of the Public Company Accounting Oversight Board or other regulatory bodies, which the Corporation is governed by;
(f)to review and discuss with the independent auditors, upon completion of their audit and prior to the filing or releasing annual financial statements:
(i)contents of their report, including:
A.all critical accounting policies and practices used;
B.all alternative treatments of financial information within GAAP that have been discussed with management, ramifications of the use of such treatments and the treatment preferred by the independent auditor;
C.other material written communications between the independent auditor and management;
(ii)scope and quality of the audit work performed;
(iii)adequacy of the Corporation’s financial and auditing personnel;
(iv)cooperation received from the Corporation’s personnel during the audit;
(v)internal resources used;
(vi)significant transactions outside of the normal business of the Corporation;

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(vii)significant proposed adjustments and recommendations for improving internal accounting controls, accounting principles or management systems;
(viii)the non-audit services provided by the independent auditors; and,
(ix)consider the independent auditor’s judgments about the quality and appropriateness of the Corporation’s accounting principles and critical accounting estimates as applied in its financial reporting.
(g)to review and approve a report to shareholders as required, to be included in the Corporation’s Information Circular and Proxy Statement, disclosing any non-audit services approved by the Audit Committee.
(h)to review and approve the Corporation’s hiring policies regarding partners, employees and former partners and employees of the present and former independent auditor of the Corporation.
3.The duties and responsibilities of the Audit Committee as they relate to the internal auditors shall be as follows:
(a)to review the budget, internal audit function with respect to the organization structure, staffing, effectiveness and qualifications of the Corporation’s internal audit department;
(b)to review the internal audit plan; and
(c)to review significant internal audit findings and recommendations together with management’s response and follow-up thereto.
4.The duties and responsibilities of the Audit Committee as they relate to the internal control procedures of the Corporation shall be as follows:
(a)to review the appropriateness and effectiveness of the Corporation’s policies and business practices which impact on the financial integrity of the Corporation, including those relating to internal auditing, insurance, accounting, information services and systems and financial controls, management reporting (including financial reporting) and the management of risk related thereto;
(b)to review any unresolved issues between management and the independent auditors that could affect the financial reporting or internal controls of the Corporation; and
(c)to periodically review the extent to which recommendations made by the internal audit staff or by the independent auditors have been implemented.
5.Other duties and responsibilities of the Audit Committee shall be as follows:
(a)to review and discuss with management, the internal audit group and the independent auditors, the Corporation’s unaudited quarterly consolidated financial statements and related Management Discussion & Analysis including the impact of unusual items and changes in accounting principles and estimates, the earnings press releases before disclosure to the public and report to the Board with respect thereto;
(b)to review and discuss with management, the internal audit group and the independent auditors, the Corporation’s audited annual consolidated financial statements and related Management Discussion & Analysis including the impact of unusual items and changes in accounting principles and estimates, the earnings press releases before disclosure to the public and report to the Board with respect thereto;
(c)to ensure adequate procedures are in place for the review of the Corporation’s public disclosure of financial information extracted or derived from the Corporation’s financial statements, other than the quarterly and annual earnings press releases, and periodically assess the adequacy of those procedures;
(d)to review management’s report on the appropriateness of the policies and procedures used in the preparation of the Corporation’s consolidated financial statements and other required disclosure documents and consider recommendations for any material change to such policies;
(e)to review with management, the independent auditors and if necessary with legal counsel, any litigation, claim or other contingency, including tax assessments, that could have a material effect upon the financial position or operating results of the Corporation and the manner in which such matters have been disclosed in the consolidated financial statements;
(f)to review and consider management's assessment and report on the Corporation's cyber risk and cybersecurity measures implemented by the Corporation in response to those risks;
(g)to establish procedures for:
(i)the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls, or auditing matters; and
(ii)the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters.
(h)to co-ordinate meetings with the Reserves Committee of the Corporation, the Corporation’s senior engineering management, independent evaluating engineers and auditors as required and consider such further inquiries as are necessary to approve the consolidated financial statements;

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(i)to develop a calendar of activities to be undertaken by the Audit Committee for each ensuing year and to submit the calendar in the appropriate format to the Board following each annual general meeting of shareholders;
(j)to perform any other activities consistent with this Charter, the Corporation’s By-laws and governing law, as the Audit Committee or the Board deems necessary or appropriate; and,
(k)to maintain minutes of meetings and to report on a regular basis to the Board on significant results of the foregoing activities.
The Audit Committee has the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it has direct access to the independent auditors as well as officers and employees of the Corporation. The Audit Committee has the authority to retain, at the Corporation’s expense, special legal, accounting or other consultants or experts it deems necessary in the performance of its duties. The Corporation shall at all times make adequate provisions for the payment of all fees and other compensation approved by the Audit Committee, to the Corporation’s independent auditors in connection with the issuance of its audit report, or to any consultants or experts employed by the Audit Committee.

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Principal Documents Exhibits
CANADIAN NATURAL RESOURCES LIMITED

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2023 AND 2022
February 28, 2024

Principal Documents Exhibits

Consolidated Financial Statements

Table of Contents

Management's Report | 2
Management’s Assessment of Internal Control over Financial Reporting | 3
Report of Independent Registered Public Accounting Firm | 4
Consolidated Balance Sheets | 6
Consolidated Statements o f Earnings | 7
Consolidated Statements of Comprehensiv e Income | 7
Consolidated Statements of Changes in Equity | 8
Consolidated Statements of Cash Flows | 9
Notes to the Consolidated Financial Statements | 10
1. Accounting Policies | 10
2. Changes in Accounting Policies | 16
3. Accounting Standards Issued But Not Yet Applied | 16
4. Critical Accounting Estimates and Judgements | 16
5. Inventory | 18
6. Exploration and Evaluation Assets | 18
7. Property, Plant and Equipment | 19
8. Leases | 21
9. Investments | 22
10. Other Long-Term Assets | 22
11. Long-Term Debt | 24
12. Other Long-Term Liabilities | 26
13. Income Taxes | 27
14. Share Capital | 30
15. Accumulated Other Comprehensive Incom e | 31
16. Capital Disclosures | 32
17. Net Earnings Per Common Share | 32
18. Interest and Other Financing Expense | 32
19. Financial Instruments | 33
20. Commitments and Contingencies | 36
21. Supplemental Disclosure of Cash Flow Information | 36
22. Segmented Information | 37
23. Remuneration of Directors and Senior Management | 41

1 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s

Management’s Report

The accompanying consolidated financial statements of Canadian Natural Resources Limited (the "Company") and all other information contained elsewhere in this Annual Report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with the accounting policies described in the accompanying notes. Where necessary, management has made informed judgements and estimates in accounting for transactions that were not complete at the balance sheet date. In the opinion of management, the financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board as appropriate in the circumstances. The financial information presented elsewhere in the Annual Report has been reviewed to ensure consistency with that in the consolidated financial statements.
Management maintains appropriate systems of internal control. Policies and procedures are designed to give reasonable assurance that transactions are appropriately authorized and recorded, assets are safeguarded from loss or unauthorized use and financial records are properly maintained to provide reliable information for preparation of financial statements.
PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, has been engaged, as approved by a vote of the shareholders at the Company’s most recent Annual General Meeting, to audit and provide their independent audit opinions on the following:
▪the Company’s consolidated financial statements as at and for the year ended December 31, 2023; and
▪the effectiveness of the Company’s internal control over financial reporting as at December 31, 2023.
Their report is presented with the consolidated financial statements.
The Board of Directors (the "Board") is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Board exercises this responsibility through the Audit Committee of the Board, which is comprised entirely of independent directors. The Audit Committee meets with management and the independent auditors to satisfy itself that management responsibilities are properly discharged and to review the consolidated financial statements before they are presented to the Board for approval. The consolidated financial statements have been approved by the Board on the recommendation of the Audit Committee.

SIGNED "SCOTT G. STAUTH" |  | SIGNED "MARK A. STAINTHORPE" |  | SIGNED "VICTOR C. DAREL"
SCOTT G. STAUTH |  | MARK A. STAINTHORPE, CFA |  | VICTOR C. DAREL, CPA, CA
President |  | Chief Financial Officer |  | Senior Vice-President, Finance and Principal Accounting Officer

Calgary, Alberta, Canada
February 28, 2024

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Management’s Assessment of Internal Control over Financial Reporting

Management of Canadian Natural Resources Limited (the "Company") is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) under the United States Securities Exchange Act of 1934, as amended.
Management, including the Company’s President and the Company’s Chief Financial Officer, performed an assessment of the Company’s internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO").
Based on the assessment, management has concluded that the Company’s internal control over financial reporting was effective as at December 31, 2023. Management recognizes that all internal control systems have inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, has provided an opinion on the Company’s internal control over financial reporting as at December 31, 2023, as stated in their accompanying Report of Independent Registered Public Accounting Firm.

SIGNED "SCOTT G. STAUTH" |  | SIGNED "MARK A. STAINTHORPE" |  |
SCOTT G. STAUTH |  | MARK A. STAINTHORPE, CFA |  |
President |  | Chief Financial Officer |  |

Calgary, Alberta, Canada
February 28, 2024

3 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Canadian Natural Resources Limited
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Canadian Natural Resources Limited and its subsidiaries (together, the Company) as of December 31, 2023 and 2022, and the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2023, including the related notes (collectively referred to as the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and its financial performance and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Assessment of Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Canadian Natural 2023 Annual Report | 4

P r i n c i p a l D o c u m e n t s E x h i b i t s
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Crude Oil and Natural Gas Reserves on Property, Plant and Equipment Assets in the North America Exploration and Production Segment
As described in Notes 1, 4 and 7 to the Company’s consolidated financial statements, the property, plant and equipment (PP&E) balance in the North America Exploration and Production segment was $24.6 billion as of December 31, 2023. Depletion, depreciation and amortization (DD&A) expense for the North America Exploration and Production segment was $3.6 billion for the year ended December 31, 2023. In accordance with the Company’s accounting policies, crude oil and natural gas properties in the North America Exploration and Production segment, excluding certain major components, are depleted using the unit-of-production method based on proved reserves. Estimates of the Company’s crude oil and natural gas reserves are based on estimated future prices and production costs, expected future rates of production and the timing and amount of future development expenditures. Management utilizes third party specialists, specifically independent qualified reserve evaluators, to evaluate and review its estimates of crude oil and natural gas reserves. These estimates are utilized for the calculation of DD&A expense.
The principal considerations for our determination that performing procedures relating to the impact of crude oil and natural gas reserves on PP&E assets in the North America Exploration and Production segment is a critical audit matter are that there was a significant amount of judgment by management, including the use of specialists, when developing the estimates, specifically related to the estimates of crude oil and natural gas reserves in the North America Exploration and Production segment. This led to a high degree of auditor judgment, effort and subjectivity in performing procedures and evaluating evidence obtained related to the assumptions used in developing the estimates, including estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of internal controls in the North America Exploration and Production segment relating to management’s estimates of the Company’s crude oil and natural gas reserves and the calculation of DD&A expense. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of crude oil and natural gas reserves used to determine DD&A expense for the North America Exploration and Production segment. As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings.
The procedures performed also included, among others, evaluating whether the assumptions used by management’s specialists related to estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures were reasonable considering the current and past performance of the Company, consistency with industry pricing forecasts, and whether they were consistent with evidence obtained in other areas of the audit, as applicable. Additionally, these procedures also included testing the unit-of-production rates used to calculate DD&A expense.
/s/ "PricewaterhouseCoopers LLP"
Chartered Professional Accountants
Calgary, Canada
February 28, 2024
We have served as the Company's auditor since 1973.

5 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s

Consolidated Balance Sheets

As at December 31, | Note |  | 2023 |  | 2022
(millions of Canadian dollars) |
ASSETS |  |  |  |  |
Current assets |  |  |  |  |
Cash and cash equivalents |  |  | $ | 877 |  |  | $ | 920 |
Accounts receivable |  |  | 3,189 |  |  | 3,555 |
Inventory | 5 |  | 2,034 |  |  | 1,815 |
Prepaids and other |  |  | 471 |  |  | 215 |
Investments | 9 |  | 525 |  |  | 491 |
Current portion of other long-term assets | 10 |  | 71 |  |  | 61 |
|  |  | 7,167 |  |  | 7,057 |
Exploration and evaluation assets | 6 |  | 2,208 |  |  | 2,226 |
Property, plant and equipment | 7 |  | 64,581 |  |  | 64,859 |
Lease assets | 8 |  | 1,458 |  |  | 1,447 |
Other long-term assets | 10 |  | 541 |  |  | 553 |
|  |  | $ | 75,955 |  |  | $ | 76,142 |
LIABILITIES |  |  |  |  |
Current liabilities |  |  |  |  |
Accounts payable |  |  | $ | 1,418 |  |  | $ | 1,341 |
Accrued liabilities |  |  | 3,534 |  |  | 4,209 |
Current income taxes payable |  |  | — |  |  | 1,324 |
Current portion of long-term debt | 11 |  | 980 |  |  | 404 |
Current portion of other long-term liabilities | 12 |  | 1,503 |  |  | 1,373 |
|  |  | 7,435 |  |  | 8,651 |
Long-term debt | 11 |  | 9,819 |  |  | 11,041 |
Other long-term liabilities | 12 |  | 8,686 |  |  | 8,161 |
Deferred income taxes | 13 |  | 10,183 |  |  | 10,114 |
|  |  | 36,123 |  |  | 37,967 |
SHAREHOLDERS’ EQUITY |  |  |  |  |
Share capital | 14 |  | 10,712 |  |  | 10,294 |
Retained earnings |  |  | 28,948 |  |  | 27,672 |
Accumulated other comprehensive income | 15 |  | 172 |  |  | 209 |
|  |  | 39,832 |  |  | 38,175 |
|  |  | $ | 75,955 |  |  | $ | 76,142 |

Commitments and contingencies (note 20).
Approved by the Board of Directors on February 28, 2024.

SIGNED "CATHERINE M. BEST" |  | SIGNED "N. MURRAY EDWARDS"
CATHERINE M. BEST |  | N. MURRAY EDWARDS
Chair of the Audit Committee and Director |  | Executive Chairman of the Board of Directors and Director

Canadian Natural 2023 Annual Report | 6

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Consolidated Statements of Earnings

For the years ended December 31, |  |  |  |  |  |  |
(millions of Canadian dollars, except per common share amounts) | Note |  | 2023 |  | 2022 |  | 2021
Product sales | 22 |  | $ | 40,835 |  |  | $ | 49,530 |  |  | $ | 32,854 |
Less: royalties |  |  | (4,867) |  |  | (7,232) |  |  | (2,797) |
Revenue |  |  | 35,968 |  |  | 42,298 |  |  | 30,057 |
Expenses |  |  |  |  |  |  |
Production |  |  | 8,480 |  |  | 8,712 |  |  | 7,152 |
Transportation, blending and feedstock |  |  | 9,302 |  |  | 9,973 |  |  | 6,604 |
Depletion, depreciation and amortization | 7,8 |  | 6,413 |  |  | 7,353 |  |  | 5,724 |
Administration |  |  | 452 |  |  | 415 |  |  | 366 |
Share-based compensation | 12 |  | 491 |  |  | 804 |  |  | 514 |
Asset retirement obligation accretion | 12 |  | 366 |  |  | 281 |  |  | 185 |
Interest and other financing expense | 18 |  | 636 |  |  | 549 |  |  | 711 |
Risk management activities (gain) loss | 19 |  | (2) |  |  | (35) |  |  | 36 |
Foreign exchange (gain) loss |  |  | (279) |  |  | 738 |  |  | (127) |
Gain on acquisitions |  |  | — |  |  | — |  |  | (478) |
Income from North West Redwater Partnership | 10 |  | — |  |  | — |  |  | (400) |
Gain from investments | 9 |  | (56) |  |  | (196) |  |  | (141) |
|  |  | 25,803 |  |  | 28,594 |  |  | 20,146 |
Earnings before taxes |  |  | 10,165 |  |  | 13,704 |  |  | 9,911 |
Current income tax expense | 13 |  | 1,879 |  |  | 2,906 |  |  | 1,848 |
Deferred income tax expense (recovery) | 13 |  | 53 |  |  | (139) |  |  | 399 |
Net earnings |  |  | $ | 8,233 |  |  | $ | 10,937 |  |  | $ | 7,664 |
Net earnings per common share |  |  |  |  |  |  |
Basic | 17 |  | $ | 7.54 |  |  | $ | 9.64 |  |  | $ | 6.49 |
Diluted | 17 |  | $ | 7.47 |  |  | $ | 9.52 |  |  | $ | 6.46 |

Consolidated Statements of Comprehensive Income

For the years ended December 31, |  |  |  |  |  |
(millions of Canadian dollars) |  | 2023 |  | 2022 |  | 2021
Net earnings |  | $ | 8,233 |  |  | $ | 10,937 |  |  | $ | 7,664 |
Items that may be reclassified subsequently to net earnings |  |  |  |  |  |
Net change in derivative financial instruments designated as cash flow hedges |  |  |  |  |  |
Unrealized income, net of taxes of $nil (2022 – $1 million, 2021 – $2 million) |  | 2 |  |  | 4 |  |  | 15 |
Reclassification to net earnings, net of taxes of $nil (2022 – $1 million, 2021 – $1 million) |  | (5) |  |  | (6) |  |  | (7) |
|  | (3) |  |  | (2) |  |  | 8 |
Foreign currency translation adjustment |  |  |  |  |  |
Translation of net investment |  | (34) |  |  | 212 |  |  | (17) |
Other comprehensive (loss) income, net of taxes |  | (37) |  |  | 210 |  |  | (9) |
Comprehensive income |  | $ | 8,196 |  |  | $ | 11,147 |  |  | $ | 7,655 |

7 | Canadian Natural 2023 Annual Report

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Consolidated Statements of Changes in Equity

For the years ended December 31, |  |  |  |  |  |  |
(millions of Canadian dollars) | Note |  | 2023 |  | 2022 |  | 2021
Share capital | 14 |  |  |  |  |  |
Balance – beginning of year |  |  | $ | 10,294 |  |  | $ | 10,168 |  |  | $ | 9,606 |
Issued upon exercise of stock options |  |  | 372 |  |  | 442 |  |  | 707 |
Previously recognized liability on stock options exercised for common shares |  |  | 435 |  |  | 387 |  |  | 139 |
Purchase of common shares under Normal Course Issuer Bid |  |  | (389) |  |  | (703) |  |  | (284) |
Balance – end of year |  |  | 10,712 |  |  | 10,294 |  |  | 10,168 |
Retained earnings |  |  |  |  |  |  |
Balance – beginning of year |  |  | 27,672 |  |  | 26,778 |  |  | 22,766 |
Net earnings |  |  | 8,233 |  |  | 10,937 |  |  | 7,664 |
Dividends on common shares | 14 |  | (4,028) |  |  | (5,175) |  |  | (2,355) |
Purchase of common shares under Normal Course Issuer Bid | 14 |  | (2,929) |  |  | (4,868) |  |  | (1,297) |
Balance – end of year |  |  | 28,948 |  |  | 27,672 |  |  | 26,778 |
Accumulated other comprehensive income (loss) | 15 |  |  |  |  |  |
Balance – beginning of year |  |  | 209 |  |  | (1) |  |  | 8 |
Other comprehensive (loss) income, net of taxes |  |  | (37) |  |  | 210 |  |  | (9) |
Balance – end of year |  |  | 172 |  |  | 209 |  |  | (1) |
Shareholders’ equity |  |  | $ | 39,832 |  |  | $ | 38,175 |  |  | $ | 36,945 |

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P r i n c i p a l D o c u m e n t s E x h i b i t s

Consolidated Statements of Cash Flows

For the years ended December 31, |  |  |  |  |  |  |
(millions of Canadian dollars) | Note |  | 2023 |  | 2022 |  | 2021
Operating activities |  |  |  |  |  |  |
Net earnings |  |  | $ | 8,233 |  |  | $ | 10,937 |  |  | $ | 7,664 |
Non-cash items |  |  |  |  |  |  |
Depletion, depreciation and amortization | 7,8 |  | 6,413 |  |  | 7,353 |  |  | 5,724 |
Share-based compensation |  |  | 491 |  |  | 804 |  |  | 514 |
Asset retirement obligation accretion |  |  | 366 |  |  | 281 |  |  | 185 |
Unrealized risk management loss (gain) |  |  | 12 |  |  | (28) |  |  | 19 |
Unrealized foreign exchange (gain) loss |  |  | (260) |  |  | 852 |  |  | (205) |
Gain on acquisitions |  |  | — |  |  | — |  |  | (478) |
Gain from investments |  |  | (34) |  |  | (182) |  |  | (132) |
Deferred income tax expense (recovery) |  |  | 53 |  |  | (139) |  |  | 399 |
Realized foreign exchange (gain) loss (1) |  |  | — |  |  | (62) |  |  | 118 |
Proceeds on settlement of cross currency swap |  |  | — |  |  | 89 |  |  | — |
Abandonment expenditures | 12 |  | (509) |  |  | (449) |  |  | (307) |
Other |  |  | 5 |  |  | (144) |  |  | 13 |
Net change in non-cash working capital | 21 |  | (2,417) |  |  | 79 |  |  | 964 |
Cash flows from operating activities |  |  | 12,353 |  |  | 19,391 |  |  | 14,478 |
Financing activities |  |  |  |  |  |  |
Repayment of bank credit facilities and commercial paper, net | 11,21 |  | — |  |  | (1,156) |  |  | (6,151) |
Repayment of medium-term notes | 11,21 |  | (416) |  |  | (1,498) |  |  | — |
Repayment of US dollar debt securities | 11,21 |  | — |  |  | (1,356) |  |  | (628) |
Settlement of long-term debt acquired |  |  | — |  |  | — |  |  | (183) |
Proceeds on settlement of cross currency swaps |  |  | — |  |  | 69 |  |  | — |
Payment of lease liabilities | 8,21 |  | (285) |  |  | (232) |  |  | (209) |
Issue of common shares on exercise of stock options | 14 |  | 372 |  |  | 442 |  |  | 707 |
Dividends on common shares |  |  | (3,891) |  |  | (4,926) |  |  | (2,170) |
Purchase of common shares under Normal Course Issuer Bid | 14 |  | (3,318) |  |  | (5,571) |  |  | (1,581) |
Cash flows used in financing activities |  |  | (7,538) |  |  | (14,228) |  |  | (10,215) |
Investing activities |  |  |  |  |  |  |
Net expenditures on exploration and evaluation assets | 6,22 |  | (44) |  |  | (33) |  |  | (1) |
Net expenditures on property, plant and equipment | 7,22 |  | (4,865) |  |  | (5,103) |  |  | (4,492) |
Proceeds from investment | 9 |  | — |  |  | — |  |  | 128 |
Repayment of North West Redwater Partnership subordinated debt advances | 10 |  | — |  |  | — |  |  | 555 |
Net change in non-cash working capital | 21 |  | 51 |  |  | 149 |  |  | 107 |
Cash flows used in investing activities |  |  | (4,858) |  |  | (4,987) |  |  | (3,703) |
(Decrease) increase in cash and cash equivalents |  |  | (43) |  |  | 176 |  |  | 560 |
Cash and cash equivalents – beginning of year |  |  | 920 |  |  | 744 |  |  | 184 |
Cash and cash equivalents – end of year |  |  | $ | 877 |  |  | $ | 920 |  |  | $ | 744 |
Interest paid on long-term debt, net |  |  | $ | 602 |  |  | $ | 613 |  |  | $ | 672 |
Income taxes paid (received) |  |  | $ | 3,317 |  |  | $ | 3,057 |  |  | $ | (62) |

(1)Consists of the realized foreign exchange gain on settlement of cross currency swaps in 2022, and the realized foreign exchange loss on repayment of US dollar debt securities in 2022 and 2021.

9 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s

Notes to the Consolidated Financial Statements
(tabular amounts in millions of Canadian dollars, unless otherwise stated)

1. Accounting Policies
Canadian Natural Resources Limited (the "Company") is a senior independent crude oil and natural gas exploration, development and production company. The Company’s exploration and production operations are focused in North America, largely in Western Canada; the United Kingdom ("UK") portion of the North Sea; and Côte d’Ivoire and South Africa in Offshore Africa.
The Oil Sands Mining and Upgrading segment produces synthetic crude oil through bitumen mining and upgrading operations at Horizon Oil Sands ("Horizon") and through the Company's direct and indirect interest in the Athabasca Oil Sands Project ("AOSP").
Within Western Canada, in the Midstream and Refining segment, the Company maintains certain activities that include pipeline operations, an electricity co-generation system and an investment in the North West Redwater Partnership ("NWRP"), a general partnership formed to upgrade and refine bitumen in the Province of Alberta.
The Company was incorporated in Alberta, Canada. The address of its registered office is 2100, 855 - 2 Street S.W., Calgary, Alberta, Canada.
The Company’s consolidated financial statements and the related notes have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). The accounting policies adopted by the Company under IFRS are set out below. The Company has consistently applied the same accounting policies throughout all periods presented, except where IFRS permits new accounting standards to be adopted prospectively. Changes in the Company's accounting policies are discussed in note 2.
(A) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements have been prepared under the historical cost basis, unless otherwise required.
The consolidated financial statements include the accounts of the Company and all of its subsidiary companies and wholly owned partnerships. Subsidiaries include all entities over which the Company has control. Subsidiaries are consolidated from the date on which the Company obtains control. They are deconsolidated from the date that control ceases.
Certain of the Company’s activities are conducted through joint arrangements in which two or more parties have joint control. Where the Company has determined that it has a direct ownership interest in jointly controlled assets and obligations for the liabilities (a "joint operation"), the assets, liabilities, revenue and expenses related to the joint operation are included in the consolidated financial statements in proportion to the Company’s interest. Where the Company has determined that it has an interest in jointly controlled entities (a "joint venture"), it uses the equity method of accounting. Under the equity method, the Company’s initial and subsequent investments are recognized at cost and subsequently adjusted for the Company’s share of the joint venture’s income or loss, less distributions received. If the Company’s share of the joint venture’s loss equals or exceeds its interest in the joint venture, the Company discontinues recognizing its share of further losses. The Company resumes recognizing profits when its share of profits exceeds the accumulated share of losses not recognized.
Joint ventures accounted for using the equity method of accounting are tested for impairment whenever objective evidence indicates that the carrying amount of the investment may not be recoverable. Indications of impairment include a history of losses, significant capital expenditure overruns, liquidity concerns, financial restructuring of the investee or significant adverse changes in the technological, economic or legal environment. The amount of the impairment is measured as the difference between the carrying amount of the investment and the higher of its fair value less costs of disposal and its value in use. Impairment losses are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized.
(B) INVENTORY
Inventory is primarily comprised of product inventory, materials and supplies and other inventory, including emissions credits, and is carried at the lower of cost and net realizable value. Product inventory is comprised of crude oil held for sale, including pipeline linefill and crude oil stored in floating production, storage and offloading vessels ("FPSO"). Cost of product inventory consists of purchase costs, direct production costs, directly attributable overhead and depletion, depreciation and amortization and is determined on a first-in, first-out basis. Net realizable value for product inventory is determined by reference to forward prices. Cost for materials and supplies consists of purchase costs and is based on a first-in, first-out or an average cost basis. Net realizable value for materials and supplies and other inventory is determined by reference to current market prices. Emissions credit inventory generated in the normal course of business is initially measured in accordance with the Company's accounting policy for government grants.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
(C) EXPLORATION AND EVALUATION ASSETS
Exploration and evaluation ("E&E") assets consist of the Company’s crude oil and natural gas exploration projects that are pending the determination of proved reserves.
E&E costs are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E costs do not include general prospecting or evaluation costs incurred prior to having obtained the legal rights to explore an area. These costs are recognized in net earnings.
Once the technical feasibility and commercial viability of E&E assets are determined and a development decision is made by management, the E&E assets are tested for impairment upon reclassification to property, plant and equipment. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. An E&E asset is derecognized upon disposal or when no future economic benefits are expected to arise from its use. Any gain or loss arising on derecognition of the asset is recognized in net earnings within depletion, depreciation and amortization.
E&E assets are also tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of the related Cash Generating Units ("CGUs"), aggregated at a segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks.
(D) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is measured at cost less accumulated depletion and depreciation and recoverability charges. Assets under construction are not depleted or depreciated until available for their intended use.
Exploration and Production
The cost of an asset comprises its acquisition costs, construction and development costs, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Property acquisition costs are comprised of the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
When significant components of an item of property, plant and equipment, including crude oil and natural gas interests, have different useful lives, they are accounted for separately.
Crude oil and natural gas properties are depleted using the unit-of-production method over proved reserves, except for certain major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future development expenditures required to develop proved reserves.
Oil Sands Mining and Upgrading
Capitalized costs for the Oil Sands Mining and Upgrading segment are reported separately from the Company’s North America Exploration and Production segment. Capitalized costs include acquisition costs, construction and development costs, overburden removal costs incurred during the initial development of a mine at Horizon and AOSP, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs.
Mine-related costs are depleted using the unit-of-production method based on proved reserves. Capitalized overburden removal costs are depleted over the life of the mining reserves that directly benefit from overburden removal activity. Costs of the upgraders and related infrastructure located on the Horizon and AOSP sites are depreciated on the unit-of-production method based on the estimated productive capacity of the respective upgraders and related infrastructure. Other equipment is depreciated on a straight-line basis over its estimated useful life ranging from 2 to 20 years.
Midstream, Refining and Head Office
The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream, refining and head office assets. Midstream and Refining assets are depreciated on a straight-line basis over their estimated useful lives ranging from 5 to 30 years. Head office assets are depreciated on a declining balance basis.
Useful lives
The depletion rates and expected useful lives of property, plant and equipment are reviewed on an annual basis, with changes in depletion rates and useful lives accounted for prospectively.
Derecognition
A property, plant and equipment asset is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is recognized in net earnings within depletion, depreciation and amortization.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
Major maintenance expenditures
Inspection costs associated with major turnarounds are capitalized and depreciated over the period to the next major turnaround. Maintenance costs are expensed as incurred.
Impairment
The Company assesses property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low benchmark commodity prices for an extended period of time, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related to the assets. Individual assets are grouped for impairment assessment purposes into CGUs, which are the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. A CGU's recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and a recoverability charge is taken through depletion, depreciation and amortization expense.
In subsequent periods, an assessment is made at each reporting date to determine whether there is any indication that previously recognized recoverability charges may no longer exist or may have decreased. If such indication exists, the recoverable amount is re-estimated and the net carrying amount of the asset is increased to its revised recoverable amount. The revised recoverable amount cannot exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, had no recoverability charge been recognized for the asset in prior periods. A reversal of a recoverability charge is recognized in net earnings. After a reversal, the depletion, depreciation and amortization charge is adjusted in future periods to allocate the asset’s revised carrying amount over its remaining useful life.
(E) BUSINESS COMBINATIONS
Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business combination are recognized at their fair value at the date of the acquisition. Any excess of the consideration paid over the fair value of the net assets acquired is recognized as an asset. Any excess of the fair value of the net assets acquired over the consideration paid is recognized in net earnings.
(F) LEASES
The Company recognizes a lease asset and a lease liability at the commencement date of the lease contract. The lease asset is initially measured at cost. The cost of a lease asset includes the amount of the initial measurement of the lease liability, lease payments made prior to the commencement date, initial direct costs and estimates of the asset retirement obligation, if any. Subsequent to initial recognition, the lease asset is depreciated using the straight-line method over the earlier of the end of the useful life of the lease asset or the lease term.
Lease liabilities are initially measured at the present value of lease payments discounted at the rate implicit in the lease, or if not readily determinable, the Company's incremental borrowing rate. Lease liabilities are remeasured if there are changes in the lease term or if the Company changes its assessment of whether it is reasonably certain it will exercise a purchase, extension or termination option. Lease liabilities are also remeasured if there are changes in the estimate of the amounts payable under the lease due to changes in indices or rates, or residual value guarantees.
Lease assets are reported in a separate caption in the consolidated balance sheet. Lease liabilities are reported within other long-term liabilities in the consolidated balance sheet.
Where the Company acts as the operator of a joint operation, the Company recognizes 100% of the related lease asset and lease liability. As the Company recovers its joint operation partners' share of the costs of the lease contract, these recoveries are recognized as other income in the consolidated statements of earnings.
(G) ASSET RETIREMENT OBLIGATIONS
The Company provides for asset retirement obligations on all of its property, plant and equipment and certain exploration and evaluation assets based on current legislation and operating practices. Provisions for asset retirement obligations related to property, plant and equipment are recognized as a liability in the period in which they are incurred. Provisions are measured at the present value of management’s best estimate of expenditures required to settle the obligation as at the date of the balance sheets. Subsequent to the initial measurement, the obligation is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense, whereas changes due to discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and equipment. Actual costs incurred upon settlement of the asset retirement obligation are charged against the provision.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
(H) FOREIGN CURRENCY TRANSLATION
Functional and presentation currency
Items included in the financial statements of the Company’s subsidiary companies and partnerships are measured using the currency of the primary economic environment in which the subsidiary operates (the "functional currency").
When the Company disposes of its entire interest in a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the foreign operation are recognized in net earnings.
(I) REVENUE RECOGNITION AND COSTS OF GOODS SOLD
Revenue from the sale of crude oil and NGLs and natural gas products is recognized when performance obligations in the sales contract are satisfied and it is probable that the Company will collect the consideration to which it is entitled. Performance obligations are generally satisfied at the point in time when the product is delivered to a location specified in a contract and control passes to the customer. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process.
Contracts for sale of the Company’s products generally have terms of less than a year, with certain contracts extending beyond one year. Contracts in North America generally specify delivery of crude oil and NGLs and natural gas throughout the term of the contract. Contracts in the North Sea and Offshore Africa generally specify delivery of crude oil at a point in time.
Sales of the Company’s crude oil and NGLs and natural gas products to customers are made pursuant to contracts based on prevailing commodity pricing at or near the time of delivery and volumes of product delivered. Revenues are typically collected in the month following delivery and accordingly, the Company has elected to apply the practical expedient to not adjust consideration for the effects of a financing component. Purchases and sales of crude oil and NGLs and natural gas with the same counterparty, made to facilitate sales to customers or potential customers, that are entered into in contemplation of one another, are combined and recorded as non-monetary exchanges and measured at the net settlement amount.
Revenue in the consolidated statement of earnings represents the Company’s share of product sales net of royalty payments to governments and other mineral interest owners. The Company discloses the disaggregation of revenues from sales of crude oil and NGLs and natural gas in the segmented information in note 22. Related costs of goods sold are comprised of production, transportation, blending and feedstock, and depletion, depreciation and amortization expenses. These amounts have been separately presented in the consolidated statements of earnings.
(J) PRODUCTION SHARING CONTRACTS
Production generated from Côte d’Ivoire in Offshore Africa is shared under the terms of various Production Sharing Contracts ("PSCs"). Product sales are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the respective government state oil companies (the "Governments"). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest is allocated to royalty expense and current income tax expense in accordance with the terms of the respective PSCs.
(K) INCOME TAX
The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets and liabilities in the consolidated financial statements and their respective tax bases.
Deferred income tax assets and liabilities are calculated using the substantively enacted income tax rates that are expected to apply when the asset or liability is recovered. Deferred income tax assets or liabilities are not recognized when they arise on the initial recognition of an asset or liability in a transaction (other than in a business combination) that, at the time of the transaction, affects neither accounting nor taxable profit. Deferred income tax assets or liabilities are also not recognized on possible future distributions of retained earnings of subsidiaries where the timing of the distribution can be controlled by the Company and it is probable that a distribution will not be made in the foreseeable future, or when distributions can be made without incurring income taxes.
Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that it is probable that future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. The carrying amount of deferred income tax assets is reviewed at each reporting date, and is reduced if it is no longer probable that sufficient future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized.
Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in different periods, using income tax rates that are substantively enacted at each reporting date.

13 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
(L) SHARE-BASED COMPENSATION
The Company’s Stock Option Plan (the "Option Plan") provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially measured based on the grant date fair value of the awards and the number of awards expected to vest. The awards are remeasured each reporting period for subsequent changes in the fair value of the liability. Fair value is determined using the Black-Scholes valuation model under a graded vesting method. Expected volatility is estimated based on historic results. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the Option Plan, consideration paid by the employee and any previously recognized liability associated with the stock options are recorded as share capital.
The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined by individual employee performance and the extent to which certain other performance measures are met. PSUs vest three years from original grant date. The liability for PSUs is initially measured in reference to the Company's stock price and the number of awards expected to vest and is remeasured at each reporting period for changes in the fair value of the liability.
The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term assets.
(M) FINANCIAL INSTRUMENTS
The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost; financial liabilities at amortized cost; and fair value through profit or loss. All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.
Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective interest method.
Cash and cash equivalents, accounts receivable and certain other long-term assets are classified as financial assets at amortized cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are solely comprised of payments of principal and interest. Investments in publicly traded shares are classified as fair value through profit or loss. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as financial liabilities at amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss.
Financial assets and liabilities are also categorized using a three-level hierarchy that reflects the significance of the inputs used in making fair value measurements for these assets and liabilities. The fair values of financial assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values of financial assets and liabilities in Level 2 are based on inputs other than Level 1 quoted prices that are observable for the asset or liability either directly (as prices) or indirectly (derived from prices). The fair values of Level 3 financial assets and liabilities are not based on observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability.
Transaction costs in respect of financial instruments at fair value through profit or loss are recognized in net earnings. Transaction costs in respect of other financial instruments are included in the initial measurement of the financial instrument.
Impairment of financial assets
At each reporting date, on a forward looking basis, the Company assesses the expected credit losses associated with its financial assets carried at amortized cost. Expected credit losses are measured as the difference between the cash flows that are due to the Company and the cash flows that the Company expects to receive, discounted at the effective interest rate determined at initial recognition. For trade accounts receivable, the Company applies the simplified approach permitted by IFRS 9, which requires expected lifetime credit losses to be recognized from initial recognition of the receivables. To measure expected credit losses, accounts receivable are grouped based on the number of days the receivables have been outstanding and internal credit assessments of the customers. Credit risk for longer-term receivables is assessed based on an external credit rating of the counterparty. For longer-term receivables with credit risk that has not increased significantly since the date of recognition, the Company measures the expected credit loss as the 12-month expected credit loss. Changes in the provision for expected credit loss are recognized in net earnings.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
(N) RISK MANAGEMENT ACTIVITIES
The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility, interest rate yield curves, and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk.
The Company documents all derivative financial instruments that are formally designated as hedging transactions at the inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis.
The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural gas commodity price contracts are recognized in risk management activities in net earnings.
Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to interest expense when the hedged item is recognized in net earnings, with the ineffective portion recognized in risk management activities in net earnings. Changes in the fair value of non-designated cross currency swap contracts are recognized in risk management activities in net earnings.
Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred under accumulated other comprehensive income and amortized into net earnings in the periods in which the underlying hedged items are recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized in net earnings. Realized gains or losses on the termination of financial instruments that have not been designated as hedges are recognized in net earnings.
Foreign currency forward contracts are periodically used to manage foreign currency cash requirements. The foreign currency forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at forward exchange rates. Changes in the fair value of foreign currency forward contracts designated as cash flow hedges are initially recorded in other comprehensive income and are reclassified to foreign exchange gains and losses when the hedged item is recognized in net earnings. Changes in the fair value of non-designated foreign currency forward contracts are recognized in risk management activities in net earnings.
(O) GOVERNMENT GRANTS
The Company receives or is eligible for government grants, including emissions credits. Government grants are recognized in net earnings when there is reasonable assurance that the Company will comply with the conditions attached to the grant and the grant will be received. Emissions performance and offset credits generated under the Alberta Technology Innovation and Emissions Reduction (“TIER”) regulation are initially recorded at the value prescribed by the Alberta TIER fund compliance rates in effect at the time the credits are recognized.
(P) PER COMMON SHARE AMOUNTS
The Company calculates basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding during the period. As the Company’s Option Plan allows for the settlement of stock options in either cash or shares at the option of the holder, diluted earnings per common share is calculated using the more dilutive of cash settlement or share settlement under the treasury stock method.
(Q) SHARE CAPITAL
Common shares are classified as equity. Costs directly attributable to the issue of new shares or options are included in equity as a deduction from proceeds, net of tax. When the Company acquires its own common shares, share capital is reduced by the average carrying value of the shares purchased. The excess of the purchase price over the average carrying value is recognized as a reduction of retained earnings. Shares are cancelled upon purchase.

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2. Changes in Accounting Policies
In May 2023, the IASB issued amendments to IAS 12 "Income Taxes" related to the accounting for deferred taxes arising in those jurisdictions implementing the Organization for Economic Co-operation and Development's Pillar Two model rules ("Pillar Two Legislation"). The amendments were effective immediately and adopted in the second quarter of 2023. Pillar Two Legislation did not have a significant impact on the Company’s financial results in 2023, and based on legislation substantively enacted to date in jurisdictions in which the Company currently operates, is not expected to have a significant impact on the Company's results in future periods.
In May 2021, the IASB issued amendments to IAS 12 "Income Taxes" to require companies to recognize deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements.
In February 2021, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to require companies to disclose their material accounting policy information rather than their significant accounting policies. To support this amendment the IASB also amended IFRS Practice Statement 2 "Making Materiality Judgements". The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements.
3. Accounting Standards Issued But Not Yet Applied
In January 2020, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to clarify that liabilities are classified as either current or non-current, depending on the existence of the substantive right at the end of the reporting period for an entity to defer settlement of the liability for at least twelve months after the reporting period. In October 2022, the IASB issued further amendments to specify that the classification of debt as current or non-current at the reporting date is not affected by covenants to be complied with after the reporting date, and added disclosure requirements about these covenants. All amendments are effective January 1, 2024 with early adoption permitted. The amendments are required to be adopted retrospectively. These amendments have no impact on the Company's consolidated financial statements.
4. Critical Accounting Estimates and Judgements
The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the preparation of the consolidated financial statements, primarily related to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts. The estimates, assumptions and judgements that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below.
(A) CRUDE OIL AND NATURAL GAS RESERVES
Purchase price allocations, depletion, depreciation and amortization, asset retirement obligations, and amounts used in impairment calculations are based on estimates of crude oil and natural gas reserves. Reserves estimates are based on estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures, all of which are subject to many uncertainties, interpretations and judgements including the potential impact of climate related matters and in accordance with related government regulations. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information.
(B) ASSET RETIREMENT OBLIGATIONS
The Company provides for asset retirement obligations on its property, plant and equipment based on current legislation and operating practices. Estimated future costs include assumptions of dates of future abandonment and technological advances and estimates of future inflation rates and discount rates. Actual costs may vary from the estimated provision due to changes in environmental legislation, the impact of inflation, changes in technology, changes in operating practices, revisions to work scope, changes in the date of abandonment due to changes in reserves life, and the potential impact of climate related matters and in accordance with related government regulations. These differences may have a material impact on the estimated provision.
(C) INCOME TAXES
The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be due.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
(D) FAIR VALUE OF DERIVATIVES AND OTHER FINANCIAL INSTRUMENTS
The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility, interest rate yield curves and foreign exchange rates.
(E) PURCHASE PRICE ALLOCATIONS
Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation, and amortization expense and impairment tests.
(F) SHARE-BASED COMPENSATION
The Company has made various assumptions in estimating the fair values of stock options granted under its Option Plan, including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the estimated fair value of the liability.
(G) IDENTIFICATION OF CGUs
CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into CGUs requires significant judgement and interpretations with respect to the integration between assets, the existence of active markets, shared infrastructures, and the way in which management monitors the Company’s operations.
(H) IMPAIRMENT OF ASSETS
The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGUs' or the assets' fair value less costs of disposal and its value in use. These calculations require the use of estimates and assumptions and are subject to change as new information becomes available, including information on future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and operating costs, after-tax discount rates (currently ranging from 10% to 12%), and income taxes. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs.
(I) LEASES
Purchase, extension and termination options are included in certain of the Company's leases to provide operational flexibility. To measure the lease liability, the Company uses judgement to assess the likelihood of exercising these options. These assessments are reviewed when significant events or circumstances indicate that the likelihood of exercising these options may have changed. The Company also uses estimates to determine its incremental borrowing costs if the interest rate implicit in the lease is not readily determinable.
(J) CONTINGENCIES
Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome of a future event. The assessment of contingencies requires the application of judgements and estimates including the determination of whether a present obligation exists and the reliable estimation of the timing and amount of cash flows required to settle the contingency.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
5. Inventory

|  | 2023 |  | 2022
Product inventory |  | $ | 546 |  |  | $ | 611 |
Materials, supplies and other |  | 1,488 |  |  | 1,204 |
|  | $ | 2,034 |  |  | $ | 1,815 |

During 2023, approximately $29 billion of purchased and produced inventory was recorded as expense (2022 – approximately $33 billion).
6. Exploration and Evaluation Assets

| Exploration and Production | Oil Sands Mining and Upgrading | Total
| North America | North Sea | Offshore Africa |  |
Cost |  |  |  |  |
At December 31, 2021 | $ | 2,057 |  | $ | — |  | $ | 91 |  | $ | 102 |  | $ | 2,250 |
Additions/Acquisitions | 41 |  | — |  | 5 |  | — |  | 46 |
Transfers to property, plant and equipment | (71) |  | — |  | — |  | — |  | (71) |
Derecognitions and other | (1) |  | — |  | — |  | — |  | (1) |
Foreign exchange adjustments | — |  | — |  | 2 |  | — |  | 2 |
At December 31, 2022 | 2,026 |  | — |  | 98 |  | 102 |  | 2,226 |
Additions/Acquisitions | 45 |  | — |  | 3 |  | — |  | 48 |
Transfers to property, plant and equipment | (38) |  | — |  | — |  | (25) |  | (63) |
Derecognitions and other | (2) |  | — |  | — |  | — |  | (2) |
Foreign exchange adjustments | — |  | — |  | (1) |  | — |  | (1) |
At December 31, 2023 | $ | 2,031 |  | $ | — |  | $ | 100 |  | $ | 77 |  | $ | 2,208 |

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7. Property, Plant and Equipment

| Exploration and Production | Oil Sands Mining and Upgrading | Midstream and Refining | Head Office | Total
| North America | North Sea | Offshore Africa |  |  |  |
Cost |  |  |  |  |  |  |
At December 31, 2021 | $ | 77,834 |  | $ | 7,438 |  | $ | 3,980 |  | $ | 46,856 |  | $ | 466 |  | $ | 508 |  | $ | 137,082 |
Additions/Acquisitions | 3,564 |  | 304 |  | 75 |  | 1,380 |  | 8 |  | 25 |  | 5,356 |
Transfers from exploration and evaluation assets | 71 |  | — |  | — |  |  | — |  | — |  | 71 |
Derecognitions (1) | (394) |  | (1) |  | — |  | (469) |  | — |  | — |  | (864) |
Disposals | — |  | — |  | — |  | (35) |  | — |  | — |  | (35) |
Foreign exchange adjustments and other | — |  | 517 |  | 277 |  | — |  | — |  | 3 |  | 797 |
At December 31, 2022 | 81,075 |  | 8,258 |  | 4,332 |  | 47,732 |  | 474 |  | 536 |  | 142,407 |
Additions/Acquisitions | 2,951 |  | 558 |  | 187 |  | 2,088 |  | 10 |  | 30 |  | 5,824 |
Transfers from exploration and evaluation assets | 38 |  | — |  | — |  | 25 |  | — |  | — |  | 63 |
Derecognitions (1) | (581) |  | — |  | — |  | (470) |  | — |  | — |  | (1,051) |
Foreign exchange adjustments and other | — |  | (210) |  | (110) |  | — |  | — |  | — |  | (320) |
At December 31, 2023 | $ | 83,483 |  | $ | 8,606 |  | $ | 4,409 |  | $ | 49,375 |  | $ | 484 |  | $ | 566 |  | $ | 146,923 |
Accumulated depletion and depreciation |  |  |  |  |
At December 31, 2021 | $ | 52,732 |  | $ | 5,951 |  | $ | 2,923 |  | $ | 8,499 |  | $ | 183 |  | $ | 394 |  | $ | 70,682 |
Expense | 3,502 |  | 117 |  | 148 |  | 1,684 |  | 15 |  | 23 |  | 5,489 |
Derecognitions (1) | (394) |  | (1) |  | — |  | (469) |  | — |  | — |  | (864) |
Disposals | — |  | — |  | — |  | (2) |  | — |  | — |  | (2) |
Recoverability charge | — |  | 1,620 |  | — |  | — |  | — |  | — |  | 1,620 |
Foreign exchange adjustments and other | (5) |  | 419 |  | 206 |  | — |  | — |  | 3 |  | 623 |
At December 31, 2022 | 55,835 |  | 8,106 |  | 3,277 |  | 9,712 |  | 198 |  | 420 |  | 77,548 |
Expense | 3,592 |  | 40 |  | 177 |  | 1,856 |  | 15 |  | 24 |  | 5,704 |
Derecognitions (1) | (581) |  | — |  | — |  | (470) |  | — |  | — |  | (1,051) |
Recoverability charge | — |  | 436 |  | — |  | — |  | — |  | — |  | 436 |
Foreign exchange adjustments and other | (6) |  | (200) |  | (96) |  | 7 |  | — |  | — |  | (295) |
At December 31, 2023 | $ | 58,840 |  | $ | 8,382 |  | $ | 3,358 |  | $ | 11,105 |  | $ | 213 |  | $ | 444 |  | $ | 82,342 |
Net book value |  |  |  |  |  |  |
At December 31, 2023 | $ | 24,643 |  | $ | 224 |  | $ | 1,051 |  | $ | 38,270 |  | $ | 271 |  | $ | 122 |  | $ | 64,581 |
At December 31, 2022 | $ | 25,240 |  | $ | 152 |  | $ | 1,055 |  | $ | 38,020 |  | $ | 276 |  | $ | 116 |  | $ | 64,859 |

(1)An asset is derecognized when no future economic benefits are expected to arise from its continued use or disposal.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked crude oil reserves as at December 31, 2022 and is accelerating abandonment. As a result, the Company completed a recoverability assessment of its assets in the North Sea, and recognized a non-cash charge of $651 million (after-tax) related to the Ninian field property, plant and equipment, comprised of a recoverability charge of $1,620 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $969 million.
As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a non-cash charge of $113 million (after-tax) related to an increase in its estimate of the future abandonment costs for the Ninian field in the North Sea. The non-cash charge is comprised of a recoverability charge of $436 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $323 million. The Company’s estimate of its asset retirement obligation liability, including the Ninian field recoverability charge and associated tax recoveries, is subject to revision in future periods as abandonment efforts progress.
As at December 31, 2023, the Company completed its normal course assessment of the recoverability of its other property, plant and equipment and exploration and evaluation assets, and determined the carrying amounts of all its cash generating units to be recoverable.
As at December 31, 2023, property, plant and equipment included project costs, not subject to depletion and depreciation, of $191 million in the Oil Sands Mining and Upgrading segment (2022 – $162 million in the Oil Sands Mining and Upgrading segment).
ACQUISITIONS IN 2022 & 2021
During 2022, the Company acquired a number of crude oil and natural gas properties in the North America Exploration and Production segment for net cash consideration of $513 million and assumed associated asset retirement obligations of $11 million. No net deferred income tax liabilities were recognized and no pre-tax gains were recognized on these transactions.
During 2021, the Company completed the acquisition of all the issued and outstanding common shares of Storm Resources Ltd. ("Storm") for total cash consideration of $771 million. In connection with the acquisition the Company assumed certain product transportation and processing commitments (note 20).
During 2021, the Company completed two acquisitions of natural gas producing assets and related processing infrastructure in the Montney region of British Columbia, including property, plant and equipment assets of $257 million and exploration and evaluation assets of $13 million, for cash consideration of $131 million. In connection with the acquisitions, the Company assumed asset retirement obligations of $58 million, other liabilities of $65 million, and recognized a deferred tax asset of $462 million. A gain of $478 million was recognized as a result of the acquisitions, representing the excess of the fair value of the net assets acquired compared with the total purchase consideration.
Acquisitions in the comparative years have been accounted for as business combinations using the acquisition method of accounting. Gains reported on the acquisitions represent the excess of the fair value of the net assets acquired compared to the total purchase consideration.

Canadian Natural 2023 Annual Report | 20

P r i n c i p a l D o c u m e n t s E x h i b i t s
8. Leases
LEASE ASSETS

| Product transportation and storage |  | Field equipment and power |  | Offshore vessels and equipment |  | Office leases and other |  | Total
At December 31, 2021 | $ | 974 |  |  | $ | 354 |  |  | $ | 99 |  |  | $ | 81 |  |  | $ | 1,508 |
Additions | 44 |  |  | 110 |  |  | 28 |  |  | — |  |  | 182 |
Depreciation | (106) |  |  | (86) |  |  | (31) |  |  | (21) |  |  | (244) |
Foreign exchange and other | — |  |  | (1) |  |  | 1 |  |  | 1 |  |  | 1 |
At December 31, 2022 | 912 |  |  | 377 |  |  | 97 |  |  | 61 |  |  | 1,447 |
Additions | 27 |  |  | 218 |  |  | 49 |  |  | 23 |  |  | 317 |
Depreciation | (98) |  |  | (111) |  |  | (45) |  |  | (19) |  |  | (273) |
Foreign exchange and other | (1) |  |  | (2) |  |  | (30) |  |  | — |  |  | (33) |
At December 31, 2023 | $ | 840 |  |  | $ | 482 |  |  | $ | 71 |  |  | $ | 65 |  |  | $ | 1,458 |

LEASE ASSETS, BY SEGMENT
As at December 31, 2023 and 2022, the Company had the following lease assets by segment:

|  | 2023 |  | 2022 |  |
Exploration and Production |  |  |  |  |  |
North America |  | $ | 280 |  |  | $ | 277 |  |  |
North Sea |  | 18 |  |  | 1 |  |  |
Offshore Africa |  | 119 |  |  | 98 |  |  |
Oil Sands Mining and Upgrading |  | 1,001 |  |  | 1,015 |  |  |
Head Office |  | 40 |  |  | 56 |  |  |
|  | $ | 1,458 |  |  | $ | 1,447 |  |  |

LEASE LIABILITIES
The Company measures its lease liabilities at the discounted value of its lease payments during the lease term. Lease liabilities at December 31, 2023 and 2022, were as follows:

|  | 2023 |  | 2022 |  |
Lease liabilities |  | $ | 1,555 |  |  | $ | 1,540 |  |  |
Less: current portion |  | 298 |  |  | 244 |  |  |
|  | $ | 1,257 |  |  | $ | 1,296 |  |  |

In addition to the lease assets disclosed above, on an ongoing basis the Company enters into short-term leases related to its Exploration and Production and Oil Sands Mining and Upgrading activities.
Other amounts included in net earnings and cash flows during 2023 and 2022 are provided below:

|  | 2023 |  | 2022 |  |
Expenses relating to short-term leases (1) |  | $ | 403 |  |  | $ | 410 |  |  |
Interest expense on lease liabilities |  | $ | 64 |  |  | $ | 60 |  |  |
Variable lease payments not included in the measurement of lease liabilities |  | $ | 59 |  |  | $ | 49 |  |  |
Total cash outflows for leases (2) |  | $ | 1,325 |  |  | $ | 1,204 |  |  |

(1)During 2023, the Company capitalized $514 million (2022 – $453 million) of short-term leases as additions to property, plant and equipment.
(2)Comprised of cash outflows relating to lease liabilities, short-term leases, and variable lease payments.

21 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
9. Investments
As at December 31, 2023 and 2022, the Company had the following investment:

|  | 2023 |  | 2022
Investment in PrairieSky Royalty Ltd. |  | $ | 525 |  |  | $ | 491 |

INVESTMENT IN PRAIRIESKY ROYALTY LTD.
The Company’s 22.6 million common shares investment in PrairieSky Royalty Ltd. ("PrairieSky") does not constitute significant influence, and is accounted for at fair value through profit or loss, measured at each reporting date. As at December 31, 2023 the market price per common share was $23.20 (December 31, 2022 – $21.70; December 31, 2021 – $13.63).
As at December 31, 2023, the Company’s investment in PrairieSky was classified as a current asset. PrairieSky is in the business of acquiring and managing oil and gas royalty income assets through indirect third-party oil and gas development.
The gain from the investment in PrairieSky was comprised as follows:

|  | 2023 |  | 2022 |  | 2021
Gain from investment |  | $ | (34) |  |  | $ | (182) |  |  | $ | (81) |
Dividend income |  | (22) |  |  | (14) |  |  | (7) |
|  | $ | (56) |  |  | $ | (196) |  |  | $ | (88) |

INVESTMENT IN INTER PIPELINE LTD.
During 2021, in accordance with a third-party offer to purchase, the Company elected to take total cash proceeds of $128 million, or $20.00 per common share, in exchange for its 6.4 million common shares investment in Inter Pipeline Ltd ("Inter Pipeline"). In 2021, the Company also recognized a $53 million gain from the investment in Inter Pipeline comprised of a $51 million fair value gain on the investment and $2 million of dividend income. The Company's investment did not constitute significant influence, and was accounted for at fair value through profit or loss, measured at each reporting date.
10. Other Long-Term Assets

|  | 2023 |  | 2022 |  |
Long-term prepayments, contracts and other (1) |  | $ | 279 |  |  | $ | 269 |  |  |
Prepaid cost of service toll |  | 179 |  |  | 199 |  |  |
Long-term inventory |  | 141 |  |  | 137 |  |  |
Risk management (note 19) |  | 13 |  |  | 9 |  |  |
|  | 612 |  |  | 614 |  |  |
Less: current portion |  | 71 |  |  | 61 |  |  |
|  | $ | 541 |  |  | $ | 553 |  |  |

(1)Includes physical product sales contracts assumed in acquisitions in prior periods, accrued interest on the deferred PRT recovery, and the unamortized portion of the Company's share bonus program.
INVESTMENT IN NORTH WEST REDWATER PARTNERSHIP
The Company has a 50% equity investment in North West Redwater Partnership ("NWRP"). NWRP operates a 50,000 barrels per day bitumen upgrader and refinery that processes approximately 12,500 barrels per day (25% toll payer) of bitumen feedstock for the Company and 37,500 barrels per day (75% toll payer) of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC"), an agent of the Government of Alberta. The Company is unconditionally obligated to pay its 25% pro rata share of the debt component of the monthly fee-for-service toll over the 40-year tolling period until 2058 (note 20). Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment (note 22).
On June 30, 2021, the equity partners together with the toll payers, agreed to optimize the structure of NWRP to better align the commercial interests of the equity partners and the toll payers (the "Optimization Transaction"). As a result, North West Refining Inc. transferred its entire 50% partnership interest in NWRP to APMC. The Company's 50% equity interest remained unchanged.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
Under the Optimization Transaction, the original term of the processing agreements was extended by 10 years from 2048 to 2058. NWRP retired higher cost subordinated debt, which carried interest rates of prime plus 6%, and issued lower cost senior secured bonds at an average rate of approximately 2.55%, reducing interest costs to NWRP and associated tolls to the toll payers. As such, NWRP repaid the Company's and APMC's subordinated debt advances of $555 million each. In addition, the Company received a $400 million distribution from NWRP during 2021.
To facilitate the Optimization Transaction, NWRP issued $500 million of 1.20% series L senior secured bonds due December 2023, $500 million of 2.00% series M senior secured bonds due December 2026, $1,000 million of 2.80% series N senior secured bonds due June 2031, and $600 million of 3.75% series O senior secured bonds due June 2051.
During 2023, NWRP repaid the $500 million of 1.20% series L senior secured bonds.
As at December 31, 2023, NWRP had borrowings of $2,559 million under the syndicated credit facility (December 31, 2022 – $2,318 million), and borrowings of $77 million under its short-term demand operating facility (December 31, 2022 – $nil).
During 2023, NWRP's syndicated credit facility was reduced by $60 million to $3,115 million (2022 – $3,175 million) following the repayment and cancellation of the portion of the non-revolving credit facility that matured in June 2023. NWRP's syndicated credit facility is comprised of a $2,175 million revolving credit facility, with $118 million maturing June 2024 and the remainder maturing June 2025, and a $940 million non-revolving credit facility maturing June 2025.
During 2022, NWRP entered into a $150 million facility to support letters of credit.
The assets, liabilities, partners’ equity, product sales and equity (loss) income related to NWRP at December 31, 2023 and 2022 were comprised as follows:

| 2023 |  | 2022
Current assets | $ | 349 |  |  | $ | 257 |
Non-current assets | $ | 10,508 |  |  | $ | 10,729 |
Current liabilities | $ | 1,054 |  |  | $ | 849 |
Non-current liabilities | $ | 10,913 |  |  | $ | 11,239 |
Partners’ equity | $ | (1,110) |  |  | $ | (1,102) |
Partners’ equity at Company's 50% interest | $ | (555) |  |  | $ | (551) |
Revenue (1) | $ | 1,527 |  |  | $ | 1,267 |
Net (loss) income (2) | $ | (8) |  |  | $ | 22 |

(1)Included in NWRP's revenue for 2023 is $335 million (2022 – $317 million) related to the Company's 25% share of the refining toll.
(2)Included in the net (loss) income for 2023 is the impact of depreciation and amortization expense of $387 million (2022 – $245 million) and interest and other financing expense of $500 million (2022 – $422 million).
The carrying value of the Company’s interest in NWRP is $nil, and as at December 31, 2023, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $555 million (2022 – $551 million). The Company's unrecognized equity loss from NWRP for 2023 was $4 million (2022 – recovery of the unrecognized share of the equity loss of $11 million; 2021 – unrecognized equity loss of $9 million and partnership distributions were $400 million).

23 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
11. Long-Term Debt

|  | 2023 |  | 2022
Canadian dollar denominated debt, unsecured |  |  |  |
Medium-term notes |  |  |  |
1.45% debentures due November 16, 2023 |  | $ | — |  |  | $ | 404 |
3.55% debentures due June 3, 2024 |  | 320 |  |  | 332 |
3.42% debentures due December 1, 2026 |  | 441 |  |  | 441 |
2.50% debentures due January 17, 2028 |  | 225 |  |  | 225 |
4.85% debentures due May 30, 2047 |  | 300 |  |  | 300 |
|  | 1,286 |  |  | 1,702 |
US dollar denominated debt, unsecured |  |  |  |
US dollar debt securities |  |  |  |
3.80% due April 15, 2024 (US$500 million) |  | 660 |  |  | 677 |
3.90% due February 1, 2025 (US$600 million) |  | 792 |  |  | 812 |
2.05% due July 15, 2025 (US$600 million) |  | 792 |  |  | 812 |
3.85% due June 1, 2027 (US$1,250 million) |  | 1,651 |  |  | 1,692 |
2.95% due July 15, 2030 (US$500 million) |  | 660 |  |  | 677 |
7.20% due January 15, 2032 (US$400 million) |  | 528 |  |  | 541 |
6.45% due June 30, 2033 (US$350 million) |  | 462 |  |  | 474 |
5.85% due February 1, 2035 (US$350 million) |  | 462 |  |  | 474 |
6.50% due February 15, 2037 (US$450 million) |  | 594 |  |  | 609 |
6.25% due March 15, 2038 (US$1,100 million) |  | 1,453 |  |  | 1,488 |
6.75% due February 1, 2039 (US$400 million) |  | 528 |  |  | 541 |
4.95% due June 1, 2047 (US$750 million) |  | 991 |  |  | 1,015 |
|  | 9,573 |  |  | 9,812 |
Long-term debt before transaction costs and original issue discounts, net |  | 10,859 |  |  | 11,514 |
Less: original issue discounts, net (1) |  | 11 |  |  | 13 |
transaction costs (1) (2) |  | 49 |  |  | 56 |
|  | 10,799 |  |  | 11,445 |
Less: current portion of long-term debt (1) (2) |  | 980 |  |  | 404 |
|  | $ | 9,819 |  |  | $ | 11,041 |

(1)The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt.
(2)Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees.

Canadian Natural 2023 Annual Report | 24

P r i n c i p a l D o c u m e n t s E x h i b i t s
BANK CREDIT FACILITIES AND COMMERCIAL PAPER
As at December 31, 2023, the Company had undrawn bank credit facilities of $5,450 million. Details of these facilities are described below. The Company also has certain other dedicated credit facilities supporting letters of credit.
▪a $100 million demand credit facility;
▪a $500 million revolving credit facility, maturing February 2025;
▪a $2,425 million revolving syndicated credit facility, maturing June 2025; and
▪a $2,425 million revolving syndicated credit facility, maturing June 2027.
During 2023, the Company extended its $2,425 million revolving syndicated credit facility, originally maturing June 2024, to June 2027.
During 2022, the Company repaid and cancelled the $1,150 million non-revolving term credit facility maturing February 2023.
During 2022, the Company discontinued its £5 million demand credit facility related to its North Sea operations.
Borrowings under the Company's revolving term credit facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, SOFR, US base rate or Canadian prime rate.
During 2022, the Company repaid and cancelled $500 million of the non-revolving portion of the term credit facility, amended the remaining facility to a $500 million revolving credit facility, and extended maturity from February 2023 to February 2024. During 2023, the Company extended its $500 million revolving credit facility from February 2024 to February 2025.
The Company’s borrowings under its US commercial paper program are authorized up to a maximum US$2,500 million. The Company reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
The Company’s weighted average interest rate on total long-term debt outstanding for the year ended December 31, 2023 was 4.8% (December 31, 2022 – 4.3%).
As at December 31, 2023, letters of credit and guarantees aggregating to $446 million were outstanding (December 31, 2022 – $637 million).
MEDIUM-TERM NOTES
During 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada, which expires in August 2025, replacing the Company's previous base shelf prospectus which would have expired in August 2023. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.
During 2023, the Company repaid $405 million of 1.45% medium-term notes.
During 2022, the Company repaid $1,000 million of 3.31% medium-term notes.
During 2022, the Company repaid through market purchases $95 million of 1.45% medium-term notes due November 2023, $169 million of 3.55% medium-term notes due June 2024, $159 million of 3.42% medium-term notes due December 2026, and $75 million of 2.50% medium-term notes due January 2028.
US DOLLAR DEBT SECURITIES
During 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States, which expires in August 2025, replacing the Company's previous base shelf prospectus which would have expired in August 2023. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.
During 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023.
SCHEDULED DEBT REPAYMENTS
Scheduled debt repayments are as follows:

Year | Repayment
2024 | $ | 980 |
2025 | $ | 1,584 |
2026 | $ | 441 |
2027 | $ | 1,651 |
2028 | $ | 225 |
Thereafter | $ | 5,978 |

25 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
12. Other Long-Term Liabilities

|  | 2023 |  | 2022
Asset retirement obligations |  | $ | 7,690 |  |  | $ | 6,908 |
Lease liabilities (note 8) |  | 1,555 |  |  | 1,540 |
Share-based compensation |  | 780 |  |  | 832 |
Transportation and processing contracts (1) |  | 87 |  |  | 159 |
Risk management (note 19) |  | 4 |  |  | 3 |
Other |  | 73 |  |  | 92 |
|  | 10,189 |  |  | 9,534 |
Less: current portion |  | 1,503 |  |  | 1,373 |
|  | $ | 8,686 |  |  | $ | 8,161 |

(1)Product transportation and processing obligations assumed from acquisitions in prior years (note 7).
ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and discounted using a weighted average discount rate of 5.2% (2022 – 5.6%; 2021 – 4.0%) and inflation rates of up to 2% (December 31, 2022 – up to 2%). Reconciliations of the discounted asset retirement obligations were as follows:

|  | 2023 |  | 2022 |  | 2021
Balance – beginning of year |  | $ | 6,908 |  |  | $ | 6,806 |  |  | $ | 5,861 |
Liabilities incurred |  | 25 |  |  | 20 |  |  | 5 |
Liabilities acquired, net |  | — |  |  | 11 |  |  | 76 |
Liabilities settled |  | (509) |  |  | (449) |  |  | (307) |
Asset retirement obligation accretion |  | 366 |  |  | 281 |  |  | 185 |
Revision of cost, inflation and timing estimates (1) |  | 621 |  |  | 897 |  |  | 508 |
Impact of regulatory changes (2) |  | — |  |  | 982 |  |  | 1,208 |
Change in discount rates |  | 314 |  |  | (1,698) |  |  | (723) |
Foreign exchange adjustments |  | (35) |  |  | 58 |  |  | (7) |
Balance – end of year |  | 7,690 |  |  | 6,908 |  |  | 6,806 |
Less: current portion |  | 634 |  |  | 495 |  |  | 249 |
|  | $ | 7,056 |  |  | $ | 6,413 |  |  | $ | 6,557 |

(1)Includes normal course revisions of cost, inflation and timing estimates, as well as revisions related to the acceleration of the abandonment and subsequent cost estimate increases on future abandonment at the Ninian field in the North Sea in 2022 and 2023.
(2)Reflects changes to the estimated timing of settlement of the Company's asset retirement obligations due to provincial regulatory changes in Alberta, British Columbia and Saskatchewan in 2022 and 2021.
Segmented Asset Retirement Obligations

|  | 2023 |  | 2022
Exploration and Production |  |  |  |
North America |  | $ | 4,471 |  |  | $ | 4,326 |
North Sea |  | 1,441 |  |  | 1,011 |
Offshore Africa |  | 165 |  |  | 143 |
Oil Sands Mining and Upgrading |  | 1,612 |  |  | 1,427 |
Midstream and Refining |  | 1 |  |  | 1 |
|  | $ | 7,690 |  |  | $ | 6,908 |

Canadian Natural 2023 Annual Report | 26

P r i n c i p a l D o c u m e n t s E x h i b i t s
SHARE-BASED COMPENSATION
The liability for share-based compensation includes costs incurred under the Company’s Option and PSU plans. The Company’s Option Plan provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The PSU plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined with reference to the value of the Company's shares, and by individual employee performance and the extent to which certain other performance measures are met.
The Company recognizes a liability for potential cash settlements under these plans. The current portion of the liability represents the maximum amount of the liability payable within the next twelve month period if all vested stock options and PSUs are settled in cash.

|  | 2023 |  | 2022 |  | 2021
Balance – beginning of year |  | $ | 832 |  |  | $ | 489 |  |  | $ | 160 |
Share-based compensation expense |  | 491 |  |  | 804 |  |  | 514 |
Cash payment for stock options surrendered and PSUs vested |  | (110) |  |  | (79) |  |  | (48) |
Transferred to common shares |  | (435) |  |  | (387) |  |  | (139) |
Other |  | 2 |  |  | 5 |  |  | 2 |
Balance – end of year |  | 780 |  |  | 832 |  |  | 489 |
Less: current portion |  | 538 |  |  | 559 |  |  | 329 |
|  | $ | 242 |  |  | $ | 273 |  |  | $ | 160 |

Included within share-based compensation liability as at December 31, 2023 was $96 million (2022 – $127 million; 2021 – $90 million) related to PSUs granted to certain executive employees.
The fair value of stock options outstanding was estimated using the Black-Scholes valuation model with the following weighted average assumptions:

|  | 2023 |  | 2022 |  | 2021
Fair value |  | $ | 35.93 |  |  | $ | 32.96 |  |  | $ | 16.98 |
Share price |  | $ | 86.81 |  |  | $ | 75.19 |  |  | $ | 53.45 |
Expected volatility |  | 30.9% |  | 35.8% |  | 35.5%
Expected dividend yield |  | 4.6% |  | 4.5% |  | 4.4%
Risk free interest rate |  | 3.6% |  | 3.8% |  | 1.1%
Expected forfeiture rate |  | 5.4% |  | 5.0% |  | 4.7%
Expected stock option life (1) |  | 4.2 years |  | 4.2 years |  | 4.2 years

(1)At original time of grant.
The intrinsic value of vested stock options at December 31, 2023 was $164 million (2022 – $208 million; 2021 – $112 million).
13. Income Taxes
The provision for income tax was as follows:

Expense (recovery) |  | 2023 |  | 2022 |  | 2021
Current corporate income tax – North America (1) |  | $ | 1,853 |  |  | $ | 2,789 |  |  | $ | 1,841 |
Current corporate income tax – North Sea |  | (6) |  |  | 69 |  |  | 7 |
Current corporate income tax – Offshore Africa |  | 73 |  |  | 74 |  |  | 21 |
Current PRT (2) – North Sea |  | (58) |  |  | (42) |  |  | (34) |
Other taxes |  | 17 |  |  | 16 |  |  | 13 |
Current income tax |  | 1,879 |  |  | 2,906 |  |  | 1,848 |
Deferred corporate income tax |  | 267 |  |  | 302 |  |  | 399 |
Deferred PRT (2) – North Sea |  | (214) |  |  | (441) |  |  | — |
Deferred income tax |  | 53 |  |  | (139) |  |  | 399 |
Income tax |  | $ | 1,932 |  |  | $ | 2,767 |  |  | $ | 2,247 |

(1)Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.
(2)Petroleum Revenue Tax.
As at December 31, 2022, the Company recognized deferred tax recoveries comprised of a deferred corporate income tax recovery of $528 million and a deferred PRT recovery of $441 million in connection with the Company's de-booking of its crude oil reserves and acceleration of the abandonment at the Ninian field in the North Sea (note 7).

27 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
As at December 31, 2023, the Company recognized deferred tax recoveries comprised of a deferred corporate income tax recovery of $118 million and a deferred PRT recovery of $205 million in connection with the increase in the Company's estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea (note 7).
The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and provincial income tax rates to earnings before taxes. The reasons for the difference are as follows:

|  | 2023 |  | 2022 |  | 2021
Canadian statutory income tax rate |  | 23.3% |  | 23.2% |  | 23.2%
Income tax provision at statutory rate |  | $ | 2,364 |  |  | $ | 3,180 |  |  | $ | 2,298 |
Effect on income taxes of: |  |  |  |  |  |
UK PRT and other taxes |  | (255) |  |  | (467) |  |  | (21) |
Impact of UK PRT and other taxes on corporate income tax |  | 105 |  |  | 190 |  |  | 11 |
Foreign and domestic tax rate differentials |  | (104) |  |  | (203) |  |  | (11) |
Non-taxable portion of capital gains |  | (35) |  |  | 65 |  |  | (26) |
Stock options exercised for common shares |  | 91 |  |  | 159 |  |  | 98 |
Non-taxable gain on corporate acquisitions |  | — |  |  | — |  |  | (110) |
Revisions arising from prior year tax filings |  | (174) |  |  | (186) |  |  | 16 |
Change in unrecognized capital loss carryforward asset |  | (35) |  |  | 65 |  |  | (26) |
Other |  | (25) |  |  | (36) |  |  | 18 |
Income tax |  | $ | 1,932 |  |  | $ | 2,767 |  |  | $ | 2,247 |

The following table summarizes the temporary differences that give rise to the net deferred income tax liability:

|  | 2023 |  | 2022
Deferred income tax liabilities |  |  |  |
Property, plant and equipment and exploration and evaluation assets |  | $ | 12,172 |  |  | $ | 11,985 |
Lease assets |  | 336 |  |  | 336 |
Investments |  | 54 |  |  | 56 |
Investment in North West Redwater Partnership |  | 904 |  |  | 903 |
Taxable PRT for corporate income tax |  | 256 |  |  | 176 |
Other |  | 41 |  |  | 25 |
|  | 13,763 |  |  | 13,481 |
Deferred income tax assets |  |  |  |
Asset retirement obligations |  | (2,098) |  |  | (1,822) |
Lease liabilities |  | (356) |  |  | (354) |
Share-based compensation |  | (31) |  |  | (33) |
Loss carryforwards |  | (417) |  |  | (652) |
Unrealized foreign exchange loss on long-term debt |  | (39) |  |  | (67) |
Deferred PRT |  | (639) |  |  | (439) |
|  | (3,580) |  |  | (3,367) |
Net deferred income tax liability |  | $ | 10,183 |  |  | $ | 10,114 |

Canadian Natural 2023 Annual Report | 28

P r i n c i p a l D o c u m e n t s E x h i b i t s
Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows:

|  | 2023 |  | 2022 |  | 2021
Property, plant and equipment and exploration and evaluation assets |  | $ | 196 |  |  | $ | (334) |  |  | $ | 184 |
Lease assets |  | 1 |  |  | (15) |  |  | (30) |
Unrealized foreign exchange on long-term debt |  | 28 |  |  | (81) |  |  | 34 |
Unrealized risk management activities |  | — |  |  | (12) |  |  | 19 |
Asset retirement obligations |  | (292) |  |  | (74) |  |  | (213) |
Lease liabilities |  | (3) |  |  | 11 |  |  | 25 |
Share-based compensation |  | 2 |  |  | (11) |  |  | (10) |
Loss carryforwards |  | 235 |  |  | 618 |  |  | 202 |
Investments |  | (2) |  |  | 21 |  |  | 21 |
Investment in North West Redwater Partnership |  | 1 |  |  | 53 |  |  | 83 |
Deferred PRT |  | 86 |  |  | (441) |  |  | — |
Taxable PRT for corporate income tax |  | (214) |  |  | 176 |  |  | — |
Other |  | 15 |  |  | (50) |  |  | 84 |
|  | $ | 53 |  |  | $ | (139) |  |  | $ | 399 |

The following table summarizes the movements of the net deferred income tax liability during the year:

|  | 2023 |  | 2022 |  | 2021
Balance – beginning of year |  | $ | 10,114 |  |  | $ | 10,220 |  |  | $ | 10,144 |
Deferred income tax expense (recovery) |  | 53 |  |  | (139) |  |  | 399 |
Deferred income tax expense included in other comprehensive (loss) income |  | — |  |  | — |  |  | 1 |
Foreign exchange adjustments |  | 16 |  |  | 33 |  |  | (2) |
Business combinations |  | — |  |  | — |  |  | (322) |
Balance – end of year |  | $ | 10,183 |  |  | $ | 10,114 |  |  | $ | 10,220 |

Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year.
The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company’s reported results of operations, financial position or liquidity.
Deferred income tax assets are recognized for temporary differences to the extent that the realization of the related tax benefit through future taxable profits is probable. Deferred PRT assets will be recovered from the UK Government, directly or through other third parties, as related abandonment expenditures are made. The Company has not recognized deferred income tax assets with respect to taxable capital loss carryforwards in excess of $1,000 million in North America, which can be carried forward indefinitely and only applied against future taxable capital gains. In addition, the Company has not recognized deferred income tax assets related to North American tax pools of approximately $950 million, which can only be claimed against income from certain oil and gas properties.
Deferred income tax liabilities have not been recognized on the unremitted net earnings of wholly controlled subsidiaries. The Company is able to control the timing and amount of distributions and no taxes are payable on distributions from these subsidiaries provided that the distributions remain within certain limits.

29 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
14. Share Capital
AUTHORIZED
Preferred shares issuable in a series.
Unlimited number of common shares without par value.

|  | 2023 |  | 2022
ISSUED COMMON SHARES |  | Number of shares (thousands) |  | Amount |  | Number of shares (thousands) |  | Amount
Balance – beginning of year |  | 1,102,636 |  |  | $ | 10,294 |  |  | 1,168,369 |  |  | $ | 10,168 |
Issued upon exercise of stock options |  | 9,822 |  |  | 372 |  |  | 11,605 |  |  | 442 |
Previously recognized liability on stock options exercised for common shares |  | — |  |  | 435 |  |  | — |  |  | 387 |
Purchase of common shares under Normal Course Issuer Bid |  | (40,050) |  |  | (389) |  |  | (77,338) |  |  | (703) |
Balance – end of year |  | 1,072,408 |  |  | $ | 10,712 |  |  | 1,102,636 |  |  | $ | 10,294 |

PREFERRED SHARES
Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges, restrictions and conditions attached to the shares will be determined by the Board of Directors of the Company.
DIVIDENDS
The Company has paid regular quarterly dividends in each year since 2001. The dividend policy undergoes periodic review by the Board of Directors and is subject to change.
On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $1.05 per common share, beginning with the dividend payable on April 5, 2024.
On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $1.00 per common share. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share.
On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share. On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share. On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share, from $0.5875 per common share.
NORMAL COURSE ISSUER BID
On March 8, 2023, the Company's application was approved for a Normal Course Issuer Bid ("NCIB") to purchase through the facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange ("NYSE"), up to 92,296,006 common shares, over a 12-month period commencing March 13, 2023 and ending March 12, 2024.
For the year ended December 31, 2023, the Company purchased 40,050,000 common shares at a weighted average price of $82.86 per common share for a total cost of $3,318 million. Retained earnings were reduced by $2,929 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2023, up to and including February 27, 2024, the Company purchased 4,000,000 common shares at a weighted average price of $85.54 per common share for a total cost of $342 million.
On February 28, 2024, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, the purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
SHARE SPLIT
On February 28, 2024, the Company's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval and the Company having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company's Annual and Special Meeting of Shareholders to be held on May 2, 2024.

Canadian Natural 2023 Annual Report | 30

P r i n c i p a l D o c u m e n t s E x h i b i t s
SHARE-BASED COMPENSATION – STOCK OPTIONS
The Company’s Option Plan provides for the granting of stock options to employees. Stock options granted under the Option Plan have terms ranging from five to six years to expiry and vest over a five-year period. The exercise price of each stock option granted is determined at the closing market price of the common shares on the TSX on the day prior to the grant. Each stock option granted provides the holder the choice to purchase one common share of the Company at the stated exercise price or receive a cash payment equal to the difference between the stated exercise price and the market price of the Company’s common shares on the date of surrender of the stock option.
The Option Plan is a "rolling 7%" plan, whereby the aggregate number of common shares that may be reserved for issuance under the plan shall not exceed 7% of the common shares outstanding from time to time.
The following table summarizes information relating to stock options outstanding at December 31, 2023 and 2022:

|  | 2023 |  | 2022
|  | Stock options (thousands) |  | Weighted average exercise price |  | Stock options (thousands) |  | Weighted average exercise price
Outstanding – beginning of year |  | 31,150 |  |  | $ | 42.37 |  |  | 38,327 |  |  | $ | 35.88 |
Granted |  | 7,024 |  |  | $ | 80.17 |  |  | 7,547 |  |  | $ | 68.15 |
Exercised for common shares |  | (9,822) |  |  | $ | 37.84 |  |  | (11,605) |  |  | $ | 38.06 |
Surrendered for cash settlement |  | (218) |  |  | $ | 38.77 |  |  | (441) |  |  | $ | 38.43 |
Forfeited |  | (1,929) |  |  | $ | 50.86 |  |  | (2,678) |  |  | $ | 41.43 |
Outstanding – end of year |  | 26,205 |  |  | $ | 53.60 |  |  | 31,150 |  |  | $ | 42.37 |
Exercisable – end of year |  | 3,672 |  |  | $ | 42.14 |  |  | 5,522 |  |  | $ | 37.60 |

The range of exercise prices of stock options outstanding and exercisable at December 31, 2023 was as follows:

|  |  |  | Stock options outstanding |  | Stock options exercisable
Range of exercise prices | Stock options outstanding (thousands) |  | Weighted average remaining term (years) |  | Weighted average exercise price |  | Stock options exercisable (thousands) |  | Weighted average exercise price
$20.76 | – | $29.99 |  |  | 5,441 |  |  | 2.01 |  | $ | 27.42 |  |  | 969 |  |  | $ | 24.84 |
$30.00 | – | $39.99 |  |  | 5,411 |  |  | 1.03 |  | $ | 36.67 |  |  | 1,227 |  |  | $ | 36.56 |
$40.00 | – | $49.99 |  |  | 2,381 |  |  | 2.41 |  | $ | 40.52 |  |  | 630 |  |  | $ | 40.50 |
$50.00 | – | $59.99 |  |  | 433 |  |  | 3.86 |  | $ | 54.24 |  |  | 30 |  |  | $ | 54.24 |
$60.00 | – | $69.99 |  |  | 3,837 |  |  | 3.49 |  | $ | 64.90 |  |  | 301 |  |  | $ | 64.21 |
$70.00 | – | $79.99 |  |  | 7,787 |  |  | 4.18 |  | $ | 78.48 |  |  | 515 |  |  | $ | 76.35 |
$80.00 | – | $86.06 |  |  | 915 |  |  | 5.72 |  | $ | 84.12 |  |  | — |  |  | $ | — |
|  |  |  | 26,205 |  |  | 2.87 |  | $ | 53.60 |  |  | 3,672 |  |  | $ | 42.14 |

15. Accumulated Other Comprehensive Income
The components of accumulated other comprehensive income, net of taxes, were as follows:

|  | 2023 |  | 2022
Derivative financial instruments designated as cash flow hedges |  | $ | 72 |  |  | $ | 75 |
Foreign currency translation adjustment |  | 100 |  |  | 134 |
|  | $ | 172 |  |  | $ | 209 |

31 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
16. Capital Disclosures
The Company has defined its capital to mean its long-term debt and consolidated shareholders’ equity, as determined at each reporting date.
The Company’s objectives when managing its capital structure are to maintain financial flexibility and balance to enable the Company to access capital markets to sustain its on-going operations and support its growth strategies. The Company primarily monitors capital on the basis of an internally derived financial measure referred to as its "debt to book capitalization ratio", which is the ratio of current and long-term debt less cash and cash equivalents divided by the sum of the carrying value of shareholders' equity plus current and long-term debt less cash and cash equivalents. The Company's internal targeted range for its debt to book capitalization ratio is 25% to 45%. The ratio may fall below or exceed the targeted range depending on the timing of acquisitions, the execution of the Company's capital program, and commodity price and foreign currency volatility. As at December 31, 2023, the ratio was below the target range at 20%.
Readers are cautioned that the debt to book capitalization ratio is not defined by IFRS and this financial measure may not be comparable to similar measures presented by other companies. Further, there are no assurances that the Company will continue to use this measure to monitor capital or will not alter the method of calculation of this measure in the future.

|  | 2023 |  | 2022
Long-term debt |  | $ | 10,799 |  |  | $ | 11,445 |
Less: cash and cash equivalents |  | 877 |  |  | 920 |
Long-term debt, net |  | $ | 9,922 |  |  | $ | 10,525 |
Total shareholders’ equity |  | $ | 39,832 |  |  | $ | 38,175 |
Debt to book capitalization |  | 20% |  | 22%

The Company is subject to a financial covenant that requires debt to book capitalization as defined in its credit facility agreements to not exceed 65%. At December 31, 2023, the Company was in compliance with this covenant.
17. Net Earnings Per Common Share

|  |  | 2023 |  | 2022 |  | 2021
Weighted average common shares outstanding – basic (thousands of shares) |  | 1,091,312 |  |  | 1,134,960 |  |  | 1,181,250 |
Effect of dilutive stock options (thousands of shares) |  | 10,812 |  |  | 14,222 |  |  | 5,307 |
Weighted average common shares outstanding – diluted (thousands of shares) |  | 1,102,124 |  |  | 1,149,182 |  |  | 1,186,557 |
Net earnings |  | $ | 8,233 |  |  | $ | 10,937 |  |  | $ | 7,664 |
Net earnings per common share | – basic |  | $ | 7.54 |  |  | $ | 9.64 |  |  | $ | 6.49 |
| – diluted |  | $ | 7.47 |  |  | $ | 9.52 |  |  | $ | 6.46 |

In 2023, the Company excluded 3,230,000 potentially anti-dilutive stock options from the calculation of diluted earnings per common share (2022 – 2,039,000; 2021 – 3,496,000).
18. Interest and Other Financing Expense

|  | 2023 |  | 2022 |  | 2021
Interest and other financing expense |  |  |  |  |  |
Long-term debt |  | $ | 627 |  |  | $ | 610 |  |  | $ | 681 |
Lease liabilities |  | 64 |  |  | 60 |  |  | 62 |
Total interest and other financing expense |  | 691 |  |  | 670 |  |  | 743 |
Total interest income and other |  | (55) |  |  | (121) |  |  | (32) |
Net interest and other financing expense |  | $ | 636 |  |  | $ | 549 |  |  | $ | 711 |

Canadian Natural 2023 Annual Report | 32

P r i n c i p a l D o c u m e n t s E x h i b i t s
19. Financial Instruments
The Company's financial instruments are comprised of cash and cash equivalents, accounts receivable, investments, risk management assets and liabilities, accounts payable, accrued liabilities, lease liabilities and long-term debt. These financial instruments, with the exception of investments and risk management assets and liabilities, are classified as financial assets and liabilities at amortized cost. Investments are classified as financial assets at fair value through profit or loss and are based on quoted market prices. Risk management assets and liabilities are classified as derivatives held for trading or as cash flow hedges.
At each measurement date, the estimated fair values of derivative financial instruments in Level 2 have been determined based on appropriate internal valuation methodologies and/or third party indications, including quoted forward prices for commodities, foreign exchange rates, interest yield curves and other volatility factors.
The changes in estimated fair values of derivative financial instruments included in the risk management asset (liability) were recognized in the financial statements as follows:

Asset (liability) |  | 2023 |  | 2022
Balance – beginning of year |  | $ | 6 |  |  | $ | 55 |
Net change in fair value of outstanding derivative financial instruments recognized in: |  |  |  |
Risk management activities (1) |  | 3 |  |  | 70 |
Foreign exchange |  | — |  |  | (119) |
Balance – end of year |  | 9 |  |  | 6 |
Less: current portion |  | 8 |  |  | — |
|  | $ | 1 |  |  | $ | 6 |

(1)Risk management assets and liabilities are disclosed in note 10 and note 12, respectively.
Net (gain) loss from risk management activities for the years ended December 31, were as follows:

|  | 2023 |  | 2022 |  | 2021
Net realized risk management (gain) loss |  | $ | (14) |  |  | $ | (7) |  |  | $ | 17 |
Net unrealized risk management loss (gain) |  | 12 |  |  | (28) |  |  | 19 |
|  | $ | (2) |  |  | $ | (35) |  |  | $ | 36 |

The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term debt. The Company's financial instruments are categorized as Level 1 with the exception of risk management assets and liabilities which are categorized as Level 2. There were no transfers between Level 1, 2 and 3 financial instruments. The fair value of the Company’s fixed rate long-term debt is outlined below:

|  | 2023 |  | 2022
|  | Carrying amount |  |  |  |  |  | Level 1 Fair Value |  | Carrying amount |  | Level 1 Fair Value
Fixed rate long-term debt (1) (2) |  | $ | (10,799) |  |  |  |  |  |  | $ | (10,795) |  |  | $ | (11,445) |  |  | $ | (10,796) |

(1)The fair value of fixed rate long-term debt has been determined based on quoted market prices.
(2)Includes the current portion of fixed rate long-term debt.

33 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
RISK MANAGEMENT
The Company periodically uses derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes.
The following provides a summary of the carrying amounts of derivative financial instruments held and a reconciliation to the Company’s consolidated balance sheets.

Asset (liability) |  | 2023 |  | 2022
Derivatives held for trading |  |  |  |
Natural gas (1) |  | $ | (3) |  |  | $ | 3 |
Foreign currency forward contracts |  | 12 |  |  | 3 |
|  | $ | 9 |  |  | $ | 6 |
Included within: |  |  |  |
Current portion of other long-term assets |  | $ | 12 |  |  | $ | 3 |
Current portion of other long-term liabilities |  | (4) |  |  | (3) |
Other long-term assets |  | 1 |  |  | 6 |
|  | $ | 9 |  |  | $ | 6 |

(1)In 2023, the Company entered into 50,000 MMBtu/d of US$1.82 AECO fixed price financial hedge contracts for the period of January to December 2024.
FINANCIAL RISK FACTORS
The Company's financial risks are consistent with those disclosed in notes 1 and 4.
a) Market risk
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. The Company’s market risk is comprised of commodity price risk, interest rate risk, and foreign currency exchange risk.
COMMODITY PRICE RISK MANAGEMENT
The Company periodically uses commodity derivative financial instruments to manage its exposure to commodity price risk associated with the sale of its future crude oil and natural gas production and with natural gas purchases.
The Company's outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable index pricing for the respective contract month.
INTEREST RATE RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on long-term debt. Interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. At December 31, 2023, the Company had no interest rate swap contracts outstanding.
FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-term debt, commercial paper and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated long-term debt, commercial paper and working capital. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based.
During 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the US$1,100 million 6.25% US dollar debt securities due March 2038. The Company realized cash proceeds of $158 million on settlement.
As at December 31, 2023, the Company had US$1,003 million of foreign currency forward contracts outstanding (December 31, 2022 – US$1,017 million), with original terms of up to 90 days, all of which were designated as derivatives held for trading.

Canadian Natural 2023 Annual Report | 34

P r i n c i p a l D o c u m e n t s E x h i b i t s
FINANCIAL INSTRUMENT SENSITIVITIES
The following table summarizes the annualized sensitivities of the Company’s 2023 net earnings and other comprehensive income to changes in the fair value of financial instruments outstanding as at December 31, 2023, resulting from changes in the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those disclosed in the Company’s other continuous disclosure documents, are limited to the impact of changes in a specified variable applied to financial instruments only and do not represent the impact of a change in the variable on the operating results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear.

| 2023 | 2022
| Increase (decrease) to net earnings | Increase (decrease) to other comprehensive income | Increase (decrease) to net earnings | Increase (decrease) to other comprehensive income
Interest rate risk |  |  |  |
Increase interest rate 1% | $ | (5) |  | $ | — |  | $ | (4) |  | $ | — |
Decrease interest rate 1% | $ | 5 |  | $ | — |  | $ | 4 |  | $ | — |
Foreign currency exchange rate risk |  |  |  |
Weakening of the Canadian dollar by US$0.01 | $ | (128) |  | $ | — |  | $ | (135) |  | $ | — |
Strengthening of the Canadian dollar by US$0.01 | $ | 125 |  | $ | — |  | $ | 131 |  | $ | — |

b) Credit risk
Credit risk is the risk that a party to a financial instrument will cause a financial loss to the Company by failing to discharge an obligation.
COUNTERPARTY CREDIT RISK MANAGEMENT
The Company’s accounts receivable are mainly with customers in the crude oil and natural gas industry and are subject to normal industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default. At December 31, 2023, substantially all of the Company’s accounts receivable were due within normal trade terms and the average expected credit loss was approximately 1% of the Company's accounts receivable balance (December 31, 2022 – 1%).
The Company is also exposed to possible losses in the event of nonperformance by counterparties to derivative financial instruments; however, the Company manages this credit risk by entering into agreements with counterparties that are substantially all investment grade financial institutions. As at December 31, 2023, the Company had net risk of $11 million with specific counterparties related to derivative financial instruments (December 31, 2022 – $7 million). The carrying amount of financial assets approximates the maximum credit exposure.
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital, consisting primarily of cash flow from operating activities, available credit facilities, commercial paper and access to debt capital markets, to meet obligations as they become due. The Company believes it has adequate bank credit facilities to provide liquidity to manage fluctuations in the timing of the receipt and/or disbursement of operating cash flows.

35 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
The maturity dates of the Company’s financial liabilities were as follows:

|  | Less than 1 year |  | 1 to less than 2 years |  | 2 to less than 5 years |  | Thereafter
Accounts payable |  | $ | 1,418 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Accrued liabilities |  | $ | 3,534 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Long-term debt (1) |  | $ | 980 |  |  | $ | 1,584 |  |  | $ | 2,317 |  |  | $ | 5,978 |
Other long-term liabilities (2) |  | $ | 302 |  |  | $ | 184 |  |  | $ | 428 |  |  | $ | 645 |
Interest and other financing expense (3) |  | $ | 582 |  |  | $ | 518 |  |  | $ | 1,257 |  |  | $ | 3,362 |

(1)Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
(2)Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $298 million; one to less than two years, $184 million; two to less than five years, $428 million; and thereafter, $645 million.
(3)Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates at December 31, 2023.
20. Commitments and Contingencies
In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company’s commitments as at December 31, 2023:

| 2024 |  | 2025 |  | 2026 |  | 2027 |  | 2028 |  | Thereafter
Product transportation and processing (1) | $ | 1,572 |  |  | $ | 1,595 |  |  | $ | 1,408 |  |  | $ | 1,358 |  |  | $ | 1,242 |  |  | $ | 13,380 |
North West Redwater Partnership service toll (2) | $ | 158 |  |  | $ | 157 |  |  | $ | 139 |  |  | $ | 126 |  |  | $ | 130 |  |  | $ | 4,985 |
Offshore vessels and equipment | $ | 36 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Field equipment and power | $ | 38 |  |  | $ | 25 |  |  | $ | 23 |  |  | $ | 22 |  |  | $ | 22 |  |  | $ | 193 |
Other | $ | 145 |  |  | $ | 111 |  |  | $ | 112 |  |  | $ | 25 |  |  | $ | 26 |  |  | $ | 355 |

(1)The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Pipeline Expansion reflects interim tolls approved by the Canada Energy Regulator in 2023, and is subject to change pending the approval of final tolls.
(2)Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in the toll is $3,011 million of interest payable over the 40-year tolling period, ending in 2058 (note 10).
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of its various development projects. These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation.
The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position.
21. Supplemental Disclosure of Cash Flow Information

|  | 2023 |  | 2022 |  | 2021
Changes in non-cash working capital: |  |  |  |  |  |
Accounts receivable |  | $ | 368 |  |  | $ | (441) |  |  | $ | (850) |
Inventory |  | (219) |  |  | (266) |  |  | (487) |
Prepaids and other |  | (23) |  |  | (20) |  |  | 39 |
Accounts payable |  | 78 |  |  | 537 |  |  | 80 |
Accrued liabilities |  | (812) |  |  | 896 |  |  | 525 |
Current income tax (liabilities) assets |  | (1,558) |  |  | (282) |  |  | 1,918 |
Other long-term liabilities |  | (200) |  |  | (196) |  |  | (154) |
Net changes in non-cash working capital |  | $ | (2,366) |  |  | $ | 228 |  |  | $ | 1,071 |
Relating to: |  |  |  |  |  |
Operating activities |  | $ | (2,417) |  |  | $ | 79 |  |  | $ | 964 |
Investing activities |  | 51 |  |  | 149 |  |  | 107 |
|  | $ | (2,366) |  |  | $ | 228 |  |  | $ | 1,071 |

Canadian Natural 2023 Annual Report | 36

P r i n c i p a l D o c u m e n t s E x h i b i t s
The following table summarizes movements in the Company's liabilities arising from financing activities for the years' ended December 31, 2023 and 2022:

|  | Long-term debt |  | Cash flow hedges on US dollar debt securities |  | Lease liabilities |  | Liabilities from financing activities
At December 31, 2021 |  | $ | 14,694 |  |  | $ | (119) |  |  | $ | 1,584 |  |  | $ | 16,159 |
Changes from financing cash flows: |  |  |  |  |  |  |  |
Repayment of long-term debt, net (1) |  | (4,010) |  |  | — |  |  | — |  |  | (4,010) |
Proceeds on settlement of cross currency swaps |  | — |  |  | 69 |  |  | — |  |  | 69 |
Payment of lease liabilities |  | — |  |  | — |  |  | (232) |  |  | (232) |
Non-cash changes: |  |  |  |  |  |  |  |
Lease additions |  | — |  |  | — |  |  | 182 |  |  | 182 |
Changes in foreign exchange and fair value (2) |  | 761 |  |  | 50 |  |  | 6 |  |  | 817 |
At December 31, 2022 |  | 11,445 |  |  | — |  |  | 1,540 |  |  | 12,985 |
Changes from financing cash flows: |  |  |  |  |  |  |  |
Repayment of long-term debt, net (1) |  | (416) |  |  | — |  |  | — |  |  | (416) |
Payment of lease liabilities |  | — |  |  | — |  |  | (285) |  |  | (285) |
Non-cash changes: |  |  |  |  |  |  |  |
Lease additions |  | — |  |  | — |  |  | 317 |  |  | 317 |
Changes in foreign exchange and fair value (2) |  | (230) |  |  | — |  |  | (17) |  |  | (247) |
At December 31, 2023 |  | $ | 10,799 |  |  | $ | — |  |  | $ | 1,555 |  |  | $ | 12,354 |

(1)Includes original issue discounts and premiums, and directly attributable transaction costs.
(2)Includes foreign exchange (gain) loss, changes in the fair value of cash flow hedges on US dollar debt securities, the amortization of original issue discounts and premiums and directly attributable transaction costs, and derecognition of lease liabilities.
22. Segmented Information
The Company’s exploration and production activities are conducted in three geographic segments: North America, North Sea and Offshore Africa. These activities include the exploration, development, production and marketing of crude oil, natural gas liquids and natural gas. The Company’s Oil Sands Mining and Upgrading activities are reported in a separate segment from exploration and production activities. Midstream and Refining activities include the Company’s pipeline operations, an electricity co-generation system and NWRP.
Segmented revenue and segmented results include transactions between business segments. Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers are based on the location of the seller. Inter-segment elimination and Other includes internal and corporate transportation and electricity charges. Production, processing and other purchasing and selling activities, that are not included in the preceding segments are also reported in the segmented information as Inter-segment eliminations and Other.
Operating segments have been determined based on the nature of the Company’s activities and the geographic locations in which the Company operates, and are consistent with the level of information regularly provided to and reviewed by the Company’s chief operating decision makers.

37 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s

|  | North America | North Sea | Offshore Africa
(millions of Canadian dollars) |  | 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | 2023 | 2022 | 2021
Segmented product sales |  |  |  |  |  |  |  |  |  |
Crude oil and NGLs (1) |  | $ | 17,375 |  | $ | 20,755 |  | $ | 14,478 |  | $ | 435 |  | $ | 623 |  | $ | 607 |  | $ | 577 |  | $ | 694 |  | $ | 420 |
Natural gas |  | 2,375 |  | 4,931 |  | 2,484 |  | 7 |  | 13 |  | 5 |  | 51 |  | 55 |  | 31 |
Other income and revenue (2) |  | 10 |  | 217 |  | 119 |  | — |  | — |  | (1) |  | 9 |  | 8 |  | 7 |
Total segmented product sales |  | 19,760 |  | 25,903 |  | 17,081 |  | 442 |  | 636 |  | 611 |  | 637 |  | 757 |  | 458 |
Less: royalties |  | (2,443) |  | (3,918) |  | (1,694) |  | (1) |  | (1) |  | (1) |  | (57) |  | (71) |  | (21) |
Segmented revenue |  | 17,317 |  | 21,985 |  | 15,387 |  | 441 |  | 635 |  | 610 |  | 580 |  | 686 |  | 437 |
Segmented expenses |  |  |  |  |  |  |  |  |  |
Production |  | 3,617 |  | 3,754 |  | 2,963 |  | 342 |  | 437 |  | 383 |  | 141 |  | 114 |  | 91 |
Transportation, blending and feedstock (1) |  | 5,808 |  | 6,394 |  | 4,772 |  | 7 |  | 6 |  | 7 |  | 1 |  | 1 |  | 1 |
Depletion, depreciation and amortization (3) |  | 3,679 |  | 3,595 |  | 3,569 |  | 494 |  | 1,747 |  | 160 |  | 213 |  | 173 |  | 142 |
Asset retirement obligation accretion |  | 234 |  | 171 |  | 101 |  | 46 |  | 33 |  | 21 |  | 8 |  | 7 |  | 6 |
Risk management activities (commodity derivatives) |  | 24 |  | 18 |  | 29 |  | — |  | — |  | — |  | — |  | — |  | — |
Gain on acquisitions |  | — |  | — |  | (478) |  | — |  | — |  | — |  | — |  | — |  | — |
Income from NWRP |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Total segmented expenses |  | 13,362 |  | 13,932 |  | 10,956 |  | 889 |  | 2,223 |  | 571 |  | 363 |  | 295 |  | 240 |
Segmented earnings (loss) |  | $ | 3,955 |  | $ | 8,053 |  | $ | 4,431 |  | $ | (448) |  | $ | (1,588) |  | $ | 39 |  | $ | 217 |  | $ | 391 |  | $ | 197 |
Non-segmented expenses |  |  |  |  |  |  |  |  |  |
Administration |  |  |  |  |  |  |  |  |  |
Share-based compensation |  |  |  |  |  |  |  |  |  |
Interest and other financing expense |  |  |  |  |  |  |  |  |  |
Risk management activities (other) |  |  |  |  |  |  |  |  |  |
Foreign exchange (gain) loss |  |  |  |  |  |  |  |  |  |
Gain from investments |  |  |  |  |  |  |  |  |  |
Total non-segmented expenses |  |  |  |  |  |  |  |
Earnings before taxes |  |  |  |  |  |  |  |  |  |
Current income tax |  |  |  |  |  |  |  |  |  |
Deferred income tax |  |  |  |  |  |  |  |  |  |
Net earnings |  |  |  |  |  |  |  |  |  |

(1)Includes blending and feedstock costs associated with the processing of third party bitumen and other purchased feedstock in the Oil Sands Mining and Upgrading segment.
(2)Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations partners' share of the costs of lease contracts.
(3)Includes a recoverability charge in depletion, depreciation and amortization, related to the Ninian field in the North Sea at December 31, 2023 for $436 million (December 31, 2022 – $1,620 million) (note 7).

Canadian Natural 2023 Annual Report | 38

P r i n c i p a l D o c u m e n t s E x h i b i t s

Oil Sands Mining and Upgrading | Midstream and Refining | Inter-segment elimination and Other | Total
2023 | 2022 | 2021 | 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | 2023 | 2022 | 2021
$ | 18,661 |  | $ | 20,804 |  | $ | 14,033 |  | $ | 76 |  | $ | 80 |  | $ | 78 |  | $ | 176 |  | $ | 53 |  | $ | (360) |  | $ | 37,300 |  | $ | 43,009 |  | $ | 29,256 |
— |  | — |  | — |  | — |  | — |  | — |  | 142 |  | 237 |  | 196 |  | 2,575 |  | 5,236 |  | 2,716 |
5 |  | 149 |  | 73 |  | 926 |  | 906 |  | 681 |  | 10 |  | 5 |  | 3 |  | 960 |  | 1,285 |  | 882 |
18,666 |  | 20,953 |  | 14,106 |  | 1,002 |  | 986 |  | 759 |  | 328 |  | 295 |  | (161) |  | 40,835 |  | 49,530 |  | 32,854 |
(2,366) |  | (3,242) |  | (1,081) |  | — |  | — |  | — |  | — |  | — |  | — |  | (4,867) |  | (7,232) |  | (2,797) |
16,300 |  | 17,711 |  | 13,025 |  | 1,002 |  | 986 |  | 759 |  | 328 |  | 295 |  | (161) |  | 35,968 |  | 42,298 |  | 30,057 |
3,989 |  | 4,076 |  | 3,414 |  | 332 |  | 271 |  | 234 |  | 59 |  | 60 |  | 67 |  | 8,480 |  | 8,712 |  | 7,152 |
2,563 |  | 2,652 |  | 1,505 |  | 664 |  | 691 |  | 550 |  | 259 |  | 229 |  | (231) |  | 9,302 |  | 9,973 |  | 6,604 |
2,011 |  | 1,822 |  | 1,838 |  | 16 |  | 16 |  | 15 |  | — |  | — |  | — |  | 6,413 |  | 7,353 |  | 5,724 |
78 |  | 70 |  | 57 |  | — |  | — |  | — |  | — |  | — |  | — |  | 366 |  | 281 |  | 185 |
— |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | 24 |  | 18 |  | 29 |
— |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | (478) |
— |  | — |  | — |  | — |  | — |  | (400) |  | — |  | — |  | — |  | — |  | — |  | (400) |
8,641 |  | 8,620 |  | 6,814 |  | 1,012 |  | 978 |  | 399 |  | 318 |  | 289 |  | (164) |  | 24,585 |  | 26,337 |  | 18,816 |
$ | 7,659 |  | $ | 9,091 |  | $ | 6,211 |  | $ | (10) |  | $ | 8 |  | $ | 360 |  | $ | 10 |  | $ | 6 |  | $ | 3 |  | $ | 11,383 |  | $ | 15,961 |  | $ | 11,241 |
|  |  |  |  |  |  |  |  | 452 |  | 415 |  | 366 |
|  |  |  |  |  |  |  |  | 491 |  | 804 |  | 514 |
|  |  |  |  |  |  |  |  | 636 |  | 549 |  | 711 |
|  |  |  |  |  |  |  |  | (26) |  | (53) |  | 7 |
|  |  |  |  |  |  |  |  | (279) |  | 738 |  | (127) |
|  |  |  |  |  |  |  |  | (56) |  | (196) |  | (141) |
|  |  |  |  |  |  |  |  | 1,218 |  | 2,257 |  | 1,330 |
|  |  |  |  |  |  |  |  | 10,165 |  | 13,704 |  | 9,911 |
|  |  |  |  |  |  |  |  | 1,879 |  | 2,906 |  | 1,848 |
|  |  |  |  |  |  |  |  | 53 |  | (139) |  | 399 |
|  |  |  |  |  |  |  |  | $ | 8,233 |  | $ | 10,937 |  | $ | 7,664 |

39 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
CAPITAL EXPENDITURES (1)

| 2023 |  | 2022
| Net expenditures |  | Non-cash and fair value changes (2) |  | Capitalized costs |  | Net expenditures |  | Non-cash and fair value changes (2) |  | Capitalized costs
Exploration and evaluation assets |  |  |  |  |  |  |  |  |  |  |
Exploration and Production |  |  |  |  |  |  |  |  |  |  |
North America | $ | 41 |  |  | $ | (36) |  |  | $ | 5 |  |  | $ | 28 |  |  | $ | (59) |  |  | $ | (31) |
Offshore Africa | 3 |  |  | — |  |  | 3 |  |  | 5 |  |  | — |  |  | 5 |
Oil Sands Mining and Upgrading | — |  |  | (25) |  |  | (25) |  |  | — |  |  | — |  |  | — |
| 44 |  |  | (61) |  |  | (17) |  |  | 33 |  |  | (59) |  |  | (26) |
Property, plant and equipment |  |  |  |  |  |  |  |  |  |  |
Exploration and Production |  |  |  |  |  |  |  |  |  |  |
North America | 2,729 |  |  | (321) |  |  | 2,408 |  |  | 3,105 |  |  | 136 |  |  | 3,241 |
North Sea | 33 |  |  | 525 |  |  | 558 |  |  | 126 |  |  | 177 |  |  | 303 |
Offshore Africa | 169 |  |  | 18 |  |  | 187 |  |  | 119 |  |  | (44) |  |  | 75 |
| 2,931 |  |  | 222 |  |  | 3,153 |  |  | 3,350 |  |  | 269 |  |  | 3,619 |
Oil Sands Mining and Upgrading | 1,894 |  |  | (251) |  |  | 1,643 |  |  | 1,719 |  |  | (843) |  |  | 876 |
Midstream and Refining | 10 |  |  | — |  |  | 10 |  |  | 9 |  |  | (1) |  |  | 8 |
Head Office | 30 |  |  | — |  |  | 30 |  |  | 25 |  |  | — |  |  | 25 |
| 4,865 |  |  | (29) |  |  | 4,836 |  |  | 5,103 |  |  | (575) |  |  | 4,528 |
| $ | 4,909 |  |  | $ | (90) |  |  | $ | 4,819 |  |  | $ | 5,136 |  |  | $ | (634) |  |  | $ | 4,502 |

(1)This table provides a reconciliation of capitalized costs, reported in note 6 and note 7, to net expenditures reported in the investing activities section of the statements of cash flows. The reconciliation excludes the impact of foreign exchange adjustments.
(2)Derecognitions, asset retirement obligations, transfer of exploration and evaluation assets, and other fair value adjustments.
SEGMENTED ASSETS

|  | 2023 |  | 2022
Exploration and Production |  |  |  |
North America |  | $ | 30,058 |  |  | $ | 31,135 |
North Sea |  | 602 |  |  | 378 |
Offshore Africa |  | 1,380 |  |  | 1,322 |
Other |  | 32 |  |  | 54 |
Oil Sands Mining and Upgrading |  | 42,865 |  |  | 42,102 |
Midstream and Refining |  | 856 |  |  | 979 |
Head Office |  | 162 |  |  | 172 |
|  | $ | 75,955 |  |  | $ | 76,142 |

Canadian Natural 2023 Annual Report | 40

P r i n c i p a l D o c u m e n t s E x h i b i t s
23. Remuneration of Directors and Senior Management
REMUNERATION OF NON-MANAGEMENT DIRECTORS

|  | 2023 |  | 2022 |  | 2021
Fees earned |  | $ | 3 |  |  | $ | 2 |  |  | $ | 2 |

REMUNERATION OF SENIOR MANAGEMENT (1)

|  | 2023 |  | 2022 |  | 2021
Salary |  | $ | 2 |  |  | $ | 2 |  |  | $ | 2 |
Common stock option based awards |  | 13 |  |  | 12 |  |  | 10 |
Annual incentive plans |  | 5 |  |  | 5 |  |  | 6 |
Long-term incentive plans |  | 19 |  |  | 18 |  |  | 19 |
|  | $ | 39 |  |  | $ | 37 |  |  | $ | 37 |

(1)Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to shareholders for the respective years.

41 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
CANADIAN NATURAL RESOURCES LIMITED

MANAGEMENT'S DISCUSSION AND ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2023
February 28, 2024

P r i n c i p a l D o c u m e n t s E x h i b i t s

Management's Discussion and Analysis

Table of Contents

Definitions and Abbreviations | 2
Advisory | 3
Objectives and Strategy | 5
Financial and Operational Highlights | 6
Business Environment | 10
Analysis of Changes in Product Sales | 12
Daily Production | 13
Exploration and Production | 15
Oil Sands Mining and Upgrading | 19
Midstream and Refining | 20
Corporate and Other | 21
Net Capital Expenditures | 24
Liquidity and Capital Resources | 26
Commitments and Contingencies | 28
Reserves | 29
Risks and Uncertainties | 30
Environment | 31
Accounting Policies and Standards | 34
Control Environment | 37
Non-GAAP and Other Financial Measures | 38
Outlook | 44
Other | 44

1 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
Definitions and Abbreviations

AECO | Alberta natural gas reference location
AIF | Annual Information Form
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
Bcf/d | billion cubic feet per day
Bitumen | a 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 methods
BOE | barrels of oil equivalent
BOE/d | barrels of oil equivalent per day
Brent | Dated Brent
C$ | Canadian dollars
CAGR | compound annual growth rate
CAPEX | capital expenditures
CO 2 | carbon dioxide
CO 2 e | carbon dioxide equivalents
Crude oil | includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic crude oil
CSS | Cyclic Steam Stimulation
EOR | Enhanced Oil Recovery
E&P | Exploration and Production
FASB | Financial Accounting Standards Board
FPSO | Floating Production, Storage and Offloading Vessel
GHG | greenhouse gas
GJ | gigajoules
GJ/d | gigajoules per day
Horizon | Horizon Oil Sands
IASB | International Accounting Standards Board
IBOR | Interbank Offered Rate

IFRS | International Financial Reporting Standards
LNG | liquefied natural gas
Mbbl | thousand barrels
Mbbl/d | thousand barrels per day
MBOE | thousand barrels of oil equivalent
MBOE/d | thousand barrels of oil equivalent per day
Mcf | thousand cubic feet
Mcfe | thousand cubic feet equivalent
Mcf/d | thousand cubic feet per day
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
NGLs | natural gas liquids
NWRP | North West Redwater Partnership
NYMEX | New York Mercantile Exchange
NYSE | New York Stock Exchange
OPEC+ | Organization of the Petroleum Exporting Countries Plus
PRT | Petroleum Revenue Tax
SAGD | Steam-Assisted Gravity Drainage
SCO | synthetic crude oil
SEC | United States Securities and Exchange Commission
SOFR | Secured Overnight Financing Rate
Tcf | trillion cubic feet
TSX | Toronto Stock Exchange
UK | United Kingdom
US | United States
US$ | United States dollars
US GAAP | generally accepted accounting principles in the United States
WCS | Western Canadian Select
WCS Heavy Differential | WCS Heavy Differential from WTI
WTI | West Texas Intermediate reference location at Cushing, Oklahoma

Canadian Natural 2023 Annual Report | 2

P r i n c i p a l D o c u m e n t s E x h i b i t s
Advisory
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document 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 expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses, and other targets provided throughout this Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, 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 Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby thermal oil sands project, the Jackfish thermal oil sands project and 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, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the abandonment of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the impact of the Pathways Alliance ("Pathways") initiative and activities, government support for Pathways and the ability to achieve net zero emissions from oil production, 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 the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, 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; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the ability of the Company to prevent and recover from cyberattack, other cyber-related crime and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its products; unexpected disruptions or delays in the 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 the mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's and its subsidiaries' 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; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses);

3 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
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 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, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. 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.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this MD&A 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 MD&A, 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 NON-GAAP AND OTHER FINANCIAL MEASURES
This MD&A includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). Non-GAAP measures are used by the Company to evaluate its financial performance, financial position or cash flow. Descriptions of the Company’s non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided in the "Non-GAAP and Other Financial Measures" section of this MD&A.
SPECIAL NOTE REGARDING CURRENCY, FINANCIAL INFORMATION, PRODUCTION AND RESERVES
This MD&A should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2023. It should also be read in conjunction with the Company's MD&A for the three months and year ended December 31, 2023. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's audited consolidated financial statements for the year ended December 31, 2023 and this MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").
Production volumes, per unit statistics and reserves data are presented throughout this MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") 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. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.
The following discussion and analysis refers primarily to the Company's 2023 financial results compared to 2022 and 2021, unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2024. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its quarterly MD&A for the three months and year ended December 31, 2023, its Annual Information Form for the year ended December 31, 2023, and its audited consolidated financial statements for the year ended December 31, 2023, is available on SEDAR+ at www.sedarplus.ca, and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in this MD&A. This MD&A is dated February 28, 2024.

Canadian Natural 2023 Annual Report | 4

P r i n c i p a l D o c u m e n t s E x h i b i t s
Objectives and Strategy
The Company’s objective is to create value by generating cash flow and net asset value (1) 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 in a sustainable and responsible way, maintaining a commitment to environmental stewardship and safety excellence.
The Company endeavors to meet these objectives by having a defined growth and value enhancement plan for each of its products and segments. The Company takes a balanced approach to growth and investments, and focuses on creating long-term shareholder value, including through its dividend and share buyback programs, in accordance with its capital allocation policy. The Company allocates its capital by maintaining:
▪Balance among its products, namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil (2), bitumen (thermal oil), SCO and natural gas;
▪A large, balanced, diversified, high quality, long life low decline asset base;
▪Balance among acquisitions, development and exploration;
▪Balance between sources and terms of debt financing and a strong financial position; and
▪Commitment to environmental stewardship throughout the decision-making process.
The Company’s three-phase crude oil marketing strategy includes:
▪Blending various crude oil streams with diluents to create more attractive feedstock;
▪Supporting and participating in pipeline expansions and/or new additions; and
▪Supporting and participating in projects that will increase the downstream conversion capacity for heavy crude oil and bitumen (thermal oil).
Operational discipline, safe, effective and efficient operations, and cost control are fundamental to the Company and embrace the key piece of the Company's mission statement: "doing it right". By consistently managing costs throughout all cycles of the industry, the Company believes it will achieve continued growth. Effective and efficient operations and cost control are attained by developing area knowledge, and by maintaining high working interests and operator status in the Company's properties.
The Company is committed to maintaining a strong balance sheet and flexible capital structure. The Company believes it has built the necessary financial capacity to develop its reserves, execute on growth projects and take advantage of favourable acquisition opportunities. Additionally, the Company periodically utilizes its risk management hedging program to reduce the risk of volatility in commodity prices and foreign exchange rates, and corresponding cash flows.
Strategic accretive acquisitions are a key component of the Company’s strategy. The Company has used a combination of internally generated cash flows and debt and equity financing to selectively acquire properties generating future cash flows in its core areas. The Company's financial discipline, commitment to a strong balance sheet, and capacity to internally generate cash flows provides the means to responsibly and sustainably grow in the long term.
(1)Discounted value of crude oil and natural gas reserves plus value of unproved land, less net debt.
(2)Pelican Lake heavy crude oil is 12–17º API oil, which receives medium quality crude netbacks due to lower production expense and lower royalty rates.

5 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
Financial and Operational Highlights

($ millions, except per common share amounts) |  | 2023 |  | 2022 |  | 2021
Product sales (1) |  | $ | 40,835 |  |  | $ | 49,530 |  |  | $ | 32,854 |
Crude oil and NGLs |  | $ | 37,300 |  |  | $ | 43,009 |  |  | $ | 29,256 |
Natural gas |  |  |  | $ | 2,575 |  |  | $ | 5,236 |  |  | $ | 2,716 |
Net earnings |  | $ | 8,233 |  |  | $ | 10,937 |  |  | $ | 7,664 |
Per common share |  | – basic |  | $ | 7.54 |  |  | $ | 9.64 |  |  | $ | 6.49 |
|  | – diluted |  | $ | 7.47 |  |  | $ | 9.52 |  |  | $ | 6.46 |
Adjusted net earnings from operations (2) |  | $ | 8,533 |  |  | $ | 12,863 |  |  | $ | 7,420 |
Per common share |  | – basic (3) |  | $ | 7.82 |  |  | $ | 11.33 |  |  | $ | 6.28 |
|  | – diluted (3) |  | $ | 7.74 |  |  | $ | 11.19 |  |  | $ | 6.25 |
Cash flows from operating activities |  | $ | 12,353 |  |  | $ | 19,391 |  |  | $ | 14,478 |
Adjusted funds flow (2) |  | $ | 15,274 |  |  | $ | 19,791 |  |  | $ | 13,733 |
Per common share |  | – basic (3) |  | $ | 14.00 |  |  | $ | 17.44 |  |  | $ | 11.63 |
|  | – diluted (3) |  | $ | 13.86 |  |  | $ | 17.22 |  |  | $ | 11.57 |
Dividends declared per common share (4) |  | $ | 3.70 |  |  | $ | 4.60 |  |  | $ | 2.00 |
Total assets |  | $ | 75,955 |  |  | $ | 76,142 |  |  | $ | 76,665 |
Long-term debt, net (5) |  | $ | 9,922 |  |  | $ | 10,525 |  |  | $ | 13,950 |
Cash flows used in investing activities |  | $ | 4,858 |  |  | $ | 4,987 |  |  | $ | 3,703 |
Net capital expenditures (6) |  | $ | 4,909 |  |  | $ | 5,136 |  |  | $ | 4,676 |
Abandonment expenditures, net (2) |  | $ | 509 |  |  | $ | 335 |  |  | $ | 232 |
Average realized price |  |  |  |  |  |  |  |
Crude oil and NGLs - Exploration and Production ($/bbl) (3) |  | $ | 72.36 |  |  | $ | 90.64 |  |  | $ | 63.71 |
Natural gas - Exploration and Production ($/Mcf) (7) |  | $ | 3.10 |  |  | $ | 6.55 |  |  | $ | 4.07 |
SCO - Oil Sands Mining and Upgrading ($/bbl) (3) |  | $ | 100.06 |  |  | $ | 117.69 |  |  | $ | 77.95 |
Daily production, before royalties (BOE/d) |  | 1,332,105 |  |  | 1,281,434 |  |  | 1,234,906 |
Crude oil and NGLs (bbl/d) |  | 973,530 |  |  | 933,149 |  |  | 952,404 |
Natural gas (MMcf/d) (8) |  | 2,151 |  |  | 2,090 |  |  | 1,695 |

(1)Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements.
(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(4)On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $1.00 per common share, beginning with the dividend paid on January 5, 2024. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share. On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share. On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share. On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share. On November 3, 2021, the Board of Directors approved a 25% increase in the quarterly dividend to $0.5875 per common share. On March 3, 2021, the Board of Directors approved an 11% increase in the quarterly dividend to $0.47 per common share, from $0.425 per common share.
(5)Capital management measure. Refer to note 16 to the Company's audited consolidated financial statements.
(6)Non-GAAP Financial Measure. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(7)Calculated as natural gas sales divided by sales volumes.
(8)Natural gas production volumes approximate sales volumes.

Canadian Natural 2023 Annual Report | 6

P r i n c i p a l D o c u m e n t s E x h i b i t s
CONSOLIDATED NET EARNINGS AND ADJUSTED NET EARNINGS
For 2023, the Company reported net earnings of $8,233 million compared with $10,937 million for 2022 (2021 – $7,664 million). Net earnings for 2023 included non-operating losses, net of tax, of $300 million compared with non-operating losses of $1,926 million for 2022 (2021 – non-operating income of $244 million) related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on the settlement of the cross currency swap and repayment of US dollar debt securities, the gain on acquisitions, the gain from investments, a recoverability charge relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea in 2023, a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea in 2022, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for 2023 were $8,533 million compared with $12,863 million for 2022 (2021 – $7,420 million).
The decrease in net earnings and adjusted net earnings from operations for 2023 compared with 2022 primarily reflected:
▪lower realized crude oil and NGLs pricing (1) in the North America Exploration and Production segment;
▪lower realized SCO sales pricing (1) in the Oil Sands Mining and Upgrading segment; and
▪lower realized natural gas pricing in the Exploration and Production segments;
partially offset by:
▪higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and
▪higher crude oil and NGLs sales volumes in the North America Exploration and Production segment.
A detailed reconciliation of the changes in the Company's product sales is provided in the "Analysis of Changes in Product Sales" section of this MD&A.
The impacts of share-based compensation, risk management activities, fluctuations in foreign exchange rates, and the gain from investments also contributed to the movements in net earnings for 2023 from 2022. These items are discussed in detail in the relevant sections of this MD&A.
Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked crude oil reserves as at December 31, 2022 and is accelerating abandonment. As a result, the Company completed a recoverability assessment of its assets in the North Sea, and recognized a non-cash charge of $651 million (after-tax) related to the Ninian field property, plant and equipment, comprised of a recoverability charge of $1,620 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $969 million.
As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a non-cash charge of $113 million (after-tax) related to an increase in its estimate of the future abandonment costs for the Ninian field in the North Sea. The non-cash charge is comprised of a recoverability charge of $436 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $323 million. The Company’s estimate of its asset retirement obligation liability, including the Ninian field recoverability charge and associated tax recoveries, is subject to revision in future periods as abandonment efforts progress.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

7 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW
Cash flows from operating activities for 2023 were $12,353 million compared with $19,391 million for 2022 (2021 – $14,478 million). The decrease in cash flows from operating activities for 2023 from 2022 were primarily due to the factors previously noted related to the decrease in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital.
Adjusted funds flow for 2023 was $15,274 million ($14.00 per common share) compared with $19,791 million ($17.44 per common share) for 2022 (2021 – $13,733 million; $11.63 per common share). The decrease in adjusted funds flow for 2023 from 2022 was primarily due to the factors noted above related to the decrease in cash flows from operating activities, excluding the impact of the net change in non-cash working capital, abandonment expenditures, government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets, including the unamortized cost of the share bonus program, accrued interest on the deferred PRT recovery, and prepaid cost of service tolls.
PRODUCTION VOLUMES
Record crude oil and NGLs production before royalties for 2023 of 973,530 bbl/d increased 4% from 933,149 bbl/d in 2022 (2021 – 952,404 bbl/d). Record natural gas production before royalties for 2023 increased 3% to average 2,151 MMcf/d from 2,090 MMcf/d in 2022 (2021 – 1,695 MMcf/d). Total production before royalties for 2023 of 1,332,105 BOE/d increased 4% from 1,281,434 BOE/d in 2022 (2021 – 1,234,906 BOE/d). Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production" section of this MD&A.
PRODUCT PRICES
In the Company’s Exploration and Production segments, the 2023 realized crude oil and NGLs prices decreased 20% to average $72.36 per bbl from $90.64 per bbl in 2022 (2021 – $63.71 per bbl), and the 2023 realized natural gas price decreased 53% to average $3.10 per Mcf from $6.55 per Mcf in 2022 (2021 – $4.07 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company’s 2023 realized SCO sales price decreased 15% to average $100.06 per bbl from $117.69 per bbl in 2022 (2021 – $77.95 per bbl). The Company's realized pricing reflected prevailing benchmark pricing. Crude oil and NGLs and natural gas prices are discussed in detail in the "Business Environment", "Realized Product Prices - Exploration and Production", and the "Oil Sands Mining and Upgrading" sections of this MD&A.
PRODUCTION EXPENSE
In the Company’s Exploration and Production segments, the 2023 crude oil and NGLs production expense (1) decreased 11% to average $16.12 per bbl from $18.17 per bbl in 2022 (2021 – $14.71 per bbl), and natural gas production expense (1) averaged $1.30 per Mcf in 2023, an increase of 7% from $1.22 per Mcf in 2022 (2021 – $1.18 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company's 2023 production expense (1) averaged $24.32 per bbl, a decrease of 7% from $26.04 per bbl in 2022 (2021 – $20.91 per bbl). Crude oil and NGLs and natural gas production expense is discussed in detail in the "Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
(1)Calculated as respective production expense divided by respective sales volumes.

Canadian Natural 2023 Annual Report | 8

P r i n c i p a l D o c u m e n t s E x h i b i t s
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company’s quarterly financial results for the eight most recently completed quarters:

($ millions, except per common share amounts) |  |  |  |  |  |  |  |
2023 | Total |  | Dec 31 |  | Sep 30 |  | Jun 30 |  | Mar 31
Product sales (1) | $ | 40,835 |  |  | $ | 10,679 |  |  | $ | 11,762 |  |  | $ | 8,846 |  |  | $ | 9,548 |
Crude oil and NGLs | $ | 37,300 |  |  | $ | 9,829 |  |  | $ | 10,944 |  |  | $ | 8,115 |  |  | $ | 8,412 |
Natural gas | $ | 2,575 |  |  | $ | 603 |  |  | $ | 599 |  |  | $ | 522 |  |  | $ | 851 |
Net earnings | $ | 8,233 |  |  | $ | 2,627 |  |  | $ | 2,344 |  |  | $ | 1,463 |  |  | $ | 1,799 |
Net earnings per common share |  |  |  |  |  |  |  |  |
– basic | $ | 7.54 |  |  | $ | 2.43 |  |  | $ | 2.15 |  |  | $ | 1.34 |  |  | $ | 1.63 |
– diluted | $ | 7.47 |  |  | $ | 2.41 |  |  | $ | 2.13 |  |  | $ | 1.32 |  |  | $ | 1.62 |
($ millions, except per common share amounts) |  |  |  |  |  |  |  |
2022 | Total |  | Dec 31 |  | Sep 30 |  | Jun 30 |  | Mar 31
Product sales (1) | $ | 49,530 |  |  | $ | 11,012 |  |  | $ | 12,574 |  |  | $ | 13,812 |  |  | $ | 12,132 |
Crude oil and NGLs | $ | 43,009 |  |  | $ | 9,508 |  |  | $ | 11,001 |  |  | $ | 11,727 |  |  | $ | 10,773 |
Natural gas | $ | 5,236 |  |  | $ | 1,287 |  |  | $ | 1,342 |  |  | $ | 1,605 |  |  | $ | 1,002 |
Net earnings | $ | 10,937 |  |  | $ | 1,520 |  |  | $ | 2,814 |  |  | $ | 3,502 |  |  | $ | 3,101 |
Net earnings per common share |  |  |  |  |  |  |  |  |
– basic | $ | 9.64 |  |  | $ | 1.37 |  |  | $ | 2.52 |  |  | $ | 3.04 |  |  | $ | 2.66 |
– diluted | $ | 9.52 |  |  | $ | 1.36 |  |  | $ | 2.49 |  |  | $ | 3.00 |  |  | $ | 2.63 |

(1)Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements.
Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:
▪Crude oil pricing – Fluctuations in global supply/demand including crude oil production levels from OPEC+ and its impact on world supply; the impact of geopolitical and market uncertainties, including those due to the Russian invasion of Ukraine on worldwide benchmark pricing; the impact of shale oil production in North America; the impact of the WCS Heavy Differential from WTI in North America; and the impact of the differential between WTI and Brent benchmark pricing in the International segments.
▪Natural gas pricing – Fluctuations in both the demand for natural gas and inventory storage levels, third-party pipeline maintenance and outages, the impact of geopolitical and market uncertainties, the impact of seasonal conditions, and the impact of shale gas production in the US.
▪Crude oil and NGLs sales volumes – Fluctuations in production from the Kirby and Jackfish thermal oil sands projects, fluctuations in production due to the cyclic nature of the Primrose thermal oil projects, fluctuations in the Company’s drilling program in the North America Exploration and Production segment, natural decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and wildfires and a third-party pipeline outage in 2023 in the North America Exploration and Production segment. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the International segments.
▪Natural gas sales volumes – Fluctuations in production due to the Company's drilling program in the North America Exploration and Production segment, natural decline rates, the impact and timing of acquisitions, and wildfires and a third-party pipeline outage in 2023 in the North America Exploration and Production segment.
▪Production expense – Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in product mix and production volumes, seasonal conditions, increased carbon tax, fluctuating energy costs, inflationary cost pressures, cost optimizations across all segments, turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.
▪Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, a recoverability charge relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea in 2023, and a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea at December 31, 2022.
▪Share-based compensation – Fluctuations due to the measurement of fair market value of the Company's share-based compensation liability.

9 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
▪Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company’s risk management activities.
▪Interest expense – Fluctuations due to changing long-term debt levels, and the impact of movements in benchmark interest rates on outstanding floating rate long-term debt and accrued interest on the deferred PRT recovery.
▪Foreign exchange – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses were also recorded with respect to US dollar denominated debt, partially offset by the impact of any cross currency swap hedges outstanding.
▪Gain from investment – Fluctuations due to the gain from the investment in PrairieSky Royalty Ltd. shares.
Business Environment
Rising interest rates in response to persistent inflation and concerns of a global recession put downward pressure on global crude oil benchmark pricing in 2023 and heightened geopolitical tensions led to pricing volatility throughout 2023. Higher non-OPEC supply and record US production in the fourth quarter of 2023 reduced the impact of previously announced OPEC+ production cuts. Although inflationary pressures are easing, the Company has experienced and may continue to experience inflationary pressures on its operating and capital expenditures in addition to higher than normal fluctuations in commodity prices and interest rates.
Liquidity
As at December 31, 2023, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,852 million in liquidity (1). The Company also has certain other dedicated credit facilities supporting letters of credit.
The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.
Capital Spending
On December 14, 2023, the Company announced its 2024 capital budget (2) targeted at approximately $5,420 million, and targets to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024. Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns and the balancing of project risks and time horizons. The 2024 capital budget and targeted abandonment expenditures constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)Forward-looking non-GAAP Financial Measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on Net Capital Expenditures.

Canadian Natural 2023 Annual Report | 10

P r i n c i p a l D o c u m e n t s E x h i b i t s
BENCHMARK COMMODITY PRICES

(Yearly average) |  | 2023 |  | 2022 |  | 2021
WTI benchmark price (US$/bbl) |  | $ | 77.61 |  |  | $ | 94.23 |  |  | $ | 67.96 |
Dated Brent benchmark price (US$/bbl) |  | $ | 82.61 |  |  | $ | 99.80 |  |  | $ | 70.49 |
WCS Heavy Differential from WTI (US$/bbl) |  | $ | 18.62 |  |  | $ | 18.26 |  |  | $ | 13.04 |
SCO benchmark price (US$/bbl) |  | $ | 79.64 |  |  | $ | 98.66 |  |  | $ | 66.36 |
Condensate benchmark price (US$/bbl) |  | $ | 76.55 |  |  | $ | 93.69 |  |  | $ | 68.24 |
Condensate Differential from WTI (US$/bbl) |  | $ | 1.06 |  |  | $ | 0.54 |  |  | $ | (0.28) |
NYMEX benchmark price (US$/MMBtu) |  | $ | 2.74 |  |  | $ | 6.64 |  |  | $ | 3.85 |
AECO benchmark price (C$/GJ) |  | $ | 2.77 |  |  | $ | 5.28 |  |  | $ | 3.38 |
US/Canadian dollar average exchange rate (US$) |  | $ | 0.7409 |  |  | $ | 0.7686 |  |  | $ | 0.7979 |
US/Canadian dollar year end exchange rate (US$) |  | $ | 0.7573 |  |  | $ | 0.7389 |  |  | $ | 0.7901 |

Substantially all of the Company’s production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company’s realized prices are directly impacted by fluctuations in foreign exchange rates. Product revenue continued to be impacted by changes in the Canadian dollar as the Canadian dollar sales price the Company received for its crude oil and natural gas sales is based on US dollar denominated benchmarks.
Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$77.61 per bbl for 2023, a decrease of 18% from US$94.23 per bbl for 2022 (2021 – US$67.96 per bbl).
Crude oil sales contracts for the Company’s International segments are typically based on Brent pricing, which is representative of international markets and overall global supply and demand. Brent averaged US$82.61 per bbl for 2023, a decrease of 17% from US$99.80 per bbl for 2022 (2021 – US$70.49 per bbl).
The decrease in WTI and Brent pricing for 2023 from 2022 primarily reflected concerns of higher non-OPEC supply and lower than anticipated global crude oil demand, as a result of persistent inflation and the resulting increase in interest rates.
The WCS Heavy Differential averaged US$18.62 per bbl for 2023, compared with US$18.26 per bbl for 2022 (2021 – US$13.04 per bbl).
The SCO price averaged US$79.64 per bbl for 2023, a decrease of 19% from US$98.66 per bbl for 2022 (2021 – US$66.36 per bbl). The decrease in SCO pricing for 2023 from 2022 primarily reflected the decrease in WTI benchmark pricing, together with increased production and egress constraints in the Western Canadian Sedimentary Basin ("WCSB").
NYMEX natural gas prices averaged US$2.74 per MMBtu for 2023, a decrease of 59% from US$6.64 per MMBtu for 2022 (2021 – US$3.85 per MMBtu). The decrease in NYMEX natural gas prices for 2023 from 2022 primarily reflected increased production and lower storage draws due to mild winter weather in 2023. Additionally, lower global LNG prices amid ample supply put downward pressure on NYMEX benchmark prices.
AECO natural gas prices averaged $2.77 per GJ for 2023, a decrease of 48% from $5.28 per GJ for 2022 (2021 – $3.38 per GJ). The decrease in AECO natural gas prices for 2023 from 2022 primarily reflected NYMEX benchmark pricing, increased production in the WCSB, and lower storage draws due to decreased demand resulting from mild winter weather in 2023.

11 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
Analysis of Changes in Product Sales

|  |  | Changes due to |  |  |  | Changes due to |  |
($ millions) | 2021 |  | Volumes |  | Prices |  | Other |  | 2022 |  | Volumes |  | Prices |  | Other |  | 2023 |
North America |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil and NGLs | $ | 14,478 |  |  | $ | 286 |  |  | $ | 5,991 |  |  | $ | — |  |  | $ | 20,755 |  |  | $ | 730 |  |  | $ | (4,110) |  |  | $ | — |  |  | $ | 17,375 |
Natural gas | 2,484 |  |  | 584 |  |  | 1,863 |  |  | — |  |  | 4,931 |  |  | 153 |  |  | (2,709) |  |  | — |  |  | 2,375 |
Other (1) | 119 |  |  | — |  |  | — |  |  | 98 |  |  | 217 |  |  | — |  |  | — |  |  | (207) |  |  | 10 |
| 17,081 |  |  | 870 |  |  | 7,854 |  |  | 98 |  |  | 25,903 |  |  | 883 |  |  | (6,819) |  |  | (207) |  |  | 19,760 |
North Sea |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil and NGLs | 607 |  |  | (183) |  |  | 199 |  |  | — |  |  | 623 |  |  | (117) |  |  | (71) |  |  | — |  |  | 435 |
Natural gas | 5 |  |  | (2) |  |  | 10 |  |  | — |  |  | 13 |  |  | (3) |  |  | (3) |  |  | — |  |  | 7 |
Other (1) | (1) |  |  | — |  |  | — |  |  | 1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
| 611 |  |  | (185) |  |  | 209 |  |  | 1 |  |  | 636 |  |  | (120) |  |  | (74) |  |  | — |  |  | 442 |
Offshore Africa |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil and NGLs | 420 |  |  | 45 |  |  | 229 |  |  | — |  |  | 694 |  |  | 1 |  |  | (118) |  |  | — |  |  | 577 |
Natural gas | 31 |  |  | 2 |  |  | 22 |  |  | — |  |  | 55 |  |  | (8) |  |  | 4 |  |  | — |  |  | 51 |
Other (1) | 7 |  |  | — |  |  | — |  |  | 1 |  |  | 8 |  |  | — |  |  | — |  |  | 1 |  |  | 9 |
| 458 |  |  | 47 |  |  | 251 |  |  | 1 |  |  | 757 |  |  | (7) |  |  | (114) |  |  | 1 |  |  | 637 |
Oil Sands Mining and Upgrading |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil and NGLs | 14,033 |  |  | (592) |  |  | 7,363 |  |  | — |  |  | 20,804 |  |  | 1,012 |  |  | (3,155) |  |  | — |  |  | 18,661 |
Other (1) | 73 |  |  | — |  |  | — |  |  | 76 |  |  | 149 |  |  | — |  |  | — |  |  | (144) |  |  | 5 |
| 14,106 |  |  | (592) |  |  | 7,363 |  |  | 76 |  |  | 20,953 |  |  | 1,012 |  |  | (3,155) |  |  | (144) |  |  | 18,666 |
Midstream and Refining |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Midstream activities | 78 |  |  | — |  |  | — |  |  | 2 |  |  | 80 |  |  | — |  |  | — |  |  | (4) |  |  | 76 |
Refined product sales and other (1) | 681 |  |  | — |  |  | — |  |  | 225 |  |  | 906 |  |  | — |  |  | — |  |  | 20 |  |  | 926 |
| 759 |  |  | — |  |  | — |  |  | 227 |  |  | 986 |  |  | — |  |  | — |  |  | 16 |  |  | 1,002 |
Intersegment eliminations and other (2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Product sales | (164) |  |  | — |  |  | — |  |  | 454 |  |  | 290 |  |  | — |  |  | — |  |  | 28 |  |  | 318 |
Other (1) | 3 |  |  | — |  |  | — |  |  | 2 |  |  | 5 |  |  | — |  |  | — |  |  | 5 |  |  | 10 |
| (161) |  |  | — |  |  | — |  |  | 456 |  |  | 295 |  |  | — |  |  | — |  |  | 33 |  |  | 328 |
Total | $ | 32,854 |  |  | $ | 140 |  |  | $ | 15,677 |  |  | $ | 859 |  |  | $ | 49,530 |  |  | $ | 1,768 |  |  | $ | (10,162) |  |  | $ | (301) |  |  | $ | 40,835 |

(1)Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations partners' share of the costs of lease contracts.
(2)Eliminates internal transportation and electricity charges and includes production, processing and other purchasing and selling activities that are not included in the above segments.
Product sales decreased 18% to $40,835 million for 2023 from $49,530 million for 2022 (2021 – $32,854 million). The decrease in product sales was primarily the result of an overall decrease in realized commodity pricing across the Company's segments in 2023. Crude oil and NGLs and natural gas pricing are discussed in detail in the "Business Environment", "Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production" section of this MD&A.
For 2023, 3% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America (2022 – 3%; 2021 – 3%). North Sea accounted for 1% of crude oil and NGLs and natural gas product sales for 2023 (2022 – 1%; 2021 – 2%), and Offshore Africa accounted for 2% of crude oil and NGLs and natural gas product sales for 2023 (2022 – 2%; 2021 – 1%).

Canadian Natural 2023 Annual Report | 12

P r i n c i p a l D o c u m e n t s E x h i b i t s
Daily Production
DAILY PRODUCTION, BEFORE ROYALTIES

| 2023 | 2022 | 2021
Crude oil and NGLs (bbl/d) |  |  |
North America – Exploration and Production | 496,100 |  | 479,971 |  | 472,621 |
North America – Oil Sands Mining and Upgrading (1) | 451,339 |  | 425,945 |  | 448,133 |
International – Exploration and Production |  |  |
North Sea | 12,639 |  | 12,890 |  | 17,633 |
Offshore Africa | 13,452 |  | 14,343 |  | 14,017 |
Total International (2) | 26,091 |  | 27,233 |  | 31,650 |
Total Crude oil and NGLs | 973,530 |  | 933,149 |  | 952,404 |
Natural gas (MMcf/d) (3) |  |  |
North America | 2,139 |  | 2,075 |  | 1,680 |
International |  |  |
North Sea | 2 |  | 2 |  | 3 |
Offshore Africa | 10 |  | 13 |  | 12 |
Total International | 12 |  | 15 |  | 15 |
Total Natural gas | 2,151 |  | 2,090 |  | 1,695 |
Total Barrels of oil equivalent (BOE/d) | 1,332,105 |  | 1,281,434 |  | 1,234,906 |
Product mix |  |  |
Light and medium crude oil and NGLs | 10% | 11% | 10%
Pelican Lake heavy crude oil | 3% | 4% | 5%
Primary heavy crude oil | 6% | 5% | 5%
Bitumen (thermal oil) | 20% | 20% | 21%
Synthetic crude oil (1) | 34% | 33% | 36%
Natural gas | 27% | 27% | 23%
Percentage of product sales (1) (4) (5) |  |  |
Crude oil and NGLs | 93% | 88% | 91%
Natural gas | 7% | 12% | 9%

(1)SCO production before royalties excludes SCO consumed internally as diesel.
(2)"International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used.
(3)Natural gas production volumes approximate sales volumes.
(4)Net of blending and feedstock costs and excluding risk management activities.
(5)Excluding Midstream and Refining revenue.

13 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
DAILY PRODUCTION, NET OF ROYALTIES

| 2023 | 2022 | 2021
Crude oil and NGLs (bbl/d) |  |  |
North America – Exploration and Production | 406,534 |  | 374,089 |  | 404,637 |
North America – Oil Sands Mining and Upgrading | 385,996 |  | 351,740 |  | 410,385 |
International – Exploration and Production |  |  |
North Sea | 12,609 |  | 12,849 |  | 17,588 |
Offshore Africa | 12,183 |  | 12,972 |  | 13,354 |
Total International | 24,792 |  | 25,821 |  | 30,942 |
Total Crude oil and NGLs | 817,322 |  | 751,650 |  | 845,964 |
Natural gas (MMcf/d) |  |  |
North America | 2,055 |  | 1,885 |  | 1,593 |
International |  |  |
North Sea | 2 |  | 2 |  | 3 |
Offshore Africa | 10 |  | 11 |  | 11 |
Total International | 12 |  | 13 |  | 14 |
Total Natural gas | 2,067 |  | 1,898 |  | 1,607 |
Total Barrels of oil equivalent (BOE/d) | 1,161,852 |  | 1,068,063 |  | 1,113,878 |

The Company’s business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO and natural gas.
Total 2023 production before royalties averaged 1,332,105 BOE/d, an increase of 4% from 1,281,434 BOE/d in 2022 (2021 – 1,234,906 BOE/d).
Record crude oil and NGLs production before royalties for 2023 averaged 973,530 bbl/d, an increase of 4% from 933,149 bbl/d for 2022 (2021 – 952,404 bbl/d). The increase in crude oil and NGLs production for 2023 from 2022 primarily reflected stronger production in the Oil Sands Mining and Upgrading, and North America Exploration and Production segments in 2023 due to pad additions in thermal oil, drilling activity, and the impact of extreme cold weather conditions in the fourth quarter of 2022.
Annual crude oil and NGLs production for 2023 was within the Company's previously issued production target of 969,000 bbl/d to 1,001,000 bbl/d. Annual crude oil and NGLs production for 2024 is targeted to average between 977,000 bbl/d and 1,008,000 bbl/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
Natural gas production before royalties accounted for 27% of the Company's total production in 2023 on a BOE basis. Record natural gas production for 2023 of 2,151 MMcf/d increased 3% from 2,090 MMcf/d for 2022 (2021 – 1,695 MMcf/d). The increase in natural gas production for 2023 from 2022 primarily reflected 2023 drilling activity, partially offset by the impact of wildfires and a third party pipeline outage in 2023, together with natural field declines.
Annual natural gas production for 2023 was slightly below the Company's previously issued production target of 2,170 MMcf/d to 2,242 MMcf/d. Annual natural gas production for 2024 is targeted to average between 2,120 MMcf/d and 2,230 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
North America – Exploration and Production
North America crude oil and NGLs production before royalties for 2023 averaged 496,100 bbl/d, an increase of 3% from 479,971 bbl/d for 2022 (2021 – 472,621 bbl/d). The increase in North America crude oil and NGLs production for 2023 from 2022 primarily reflected pad additions in thermal oil and conventional drilling activity in 2023, partially offset by the impacts of wildfires and a third party pipeline outage in 2023, and natural field declines.
Thermal oil production before royalties for 2023 averaged 262,000 bbl/d, an increase of 4% from 252,018 bbl/d for 2022 (2021 –259,284 bbl/d). The increase in thermal oil production for 2023 from 2022 primarily reflected pad additions at Primrose and Kirby in 2023, partially offset by natural field declines.
Pelican Lake heavy crude oil production before royalties averaged 47,078 bbl/d for 2023, a decrease of 6% from 50,333 bbl/d for 2022 (2021 – 54,390 bbl/d), primarily reflecting natural field declines.
Natural gas production before royalties for 2023 averaged 2,139 MMcf/d, an increase of 3% from 2,075 MMcf/d for 2022 (2021 – 1,680 MMcf/d). The increase in natural gas production for 2023 from 2022 primarily reflected 2023 drilling activity, partially offset by the impact of wildfires and a third party pipeline outage in 2023, together with natural field declines.

Canadian Natural 2023 Annual Report | 14

P r i n c i p a l D o c u m e n t s E x h i b i t s
North America – Oil Sands Mining and Upgrading
Record SCO production before royalties for 2023 of 451,339 bbl/d increased 6% from 425,945 bbl/d for 2022 (2021 – 448,133 bbl/d). The increase in SCO production for 2023 from 2022 primarily reflected stronger production in 2023 following the impact of an extended turnaround at the non-operated Scotford Upgrader in the first half of 2022, as well as an unplanned outage at Horizon and extreme cold weather conditions impacting mining operations in the fourth quarter of 2022.
International – Exploration and Production
International crude oil and NGLs production before royalties for 2023 averaged 26,091 bbl/d, a decrease of 4% from 27,233 bbl/d for 2022 (2021 – 31,650 bbl/d). The decrease in production for 2023 from 2022 primarily reflected natural field declines.
INTERNATIONAL CRUDE OIL INVENTORY VOLUMES
The Company recognizes revenue on its crude oil production when control of the product passes to the customer and delivery has taken place. Revenue has not been recognized in the International segments on crude oil volumes held in various storage facilities or FPSOs, as follows:

(bbl) | 2023 | 2022 | 2021
International | 515,543 |  | 390,959 |  | 727,439 |

Exploration and Production
OPERATING HIGHLIGHTS

|  | 2023 |  | 2022 |  | 2021
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |
Realized price (2) |  | $ | 72.36 |  |  | $ | 90.64 |  |  | $ | 63.71 |
Transportation (2) |  | 4.23 |  |  | 4.13 |  |  | 3.86 |
Realized price, net of transportation (2) |  | 68.13 |  |  | 86.51 |  |  | 59.85 |
Royalties (3) |  | 12.55 |  |  | 18.91 |  |  | 8.59 |
Production expense (4) |  | 16.12 |  |  | 18.17 |  |  | 14.71 |
Netback (2) |  | $ | 39.46 |  |  | $ | 49.43 |  |  | $ | 36.55 |
Natural gas ($/Mcf) (1) |  |  |  |  |  |
Realized price (5) |  | $ | 3.10 |  |  | $ | 6.55 |  |  | $ | 4.07 |
Transportation (6) |  | 0.56 |  |  | 0.51 |  |  | 0.45 |
Realized price, net of transportation |  | 2.54 |  |  | 6.04 |  |  | 3.62 |
Royalties (3) |  | 0.13 |  |  | 0.61 |  |  | 0.22 |
Production expense (4) |  | 1.30 |  |  | 1.22 |  |  | 1.18 |
Netback |  | $ | 1.11 |  |  | $ | 4.21 |  |  | $ | 2.22 |
Barrels of oil equivalent ($/BOE) (1) |  |  |  |  |  |
Realized price (2) |  | $ | 50.54 |  |  | $ | 70.07 |  |  | $ | 49.67 |
Transportation (2) |  | 3.88 |  |  | 3.72 |  |  | 3.44 |
Realized price, net of transportation (2) |  | 46.66 |  |  | 66.35 |  |  | 46.23 |
Royalties (3) |  | 7.77 |  |  | 12.75 |  |  | 5.98 |
Production expense (4) |  | 12.74 |  |  | 13.76 |  |  | 11.98 |
Netback (2) |  | $ | 26.15 |  |  | $ | 39.84 |  |  | $ | 28.27 |

(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as royalties divided by respective sales volumes.
(4)Calculated as production expense divided by respective sales volumes.
(5)Calculated as natural gas sales divided by natural gas sales volumes.
(6)Calculated as natural gas transportation expense divided by natural gas sales volumes.

15 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION

|  | 2023 |  | 2022 |  | 2021
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |
North America (2) |  | $ | 70.51 |  |  | $ | 88.43 |  |  | $ | 62.10 |
International average (3) |  | $ | 107.46 |  |  | $ | 128.41 |  |  | $ | 87.04 |
North Sea (3) |  | $ | 110.99 |  |  | $ | 129.04 |  |  | $ | 87.98 |
Offshore Africa (3) |  | $ | 106.25 |  |  | $ | 127.85 |  |  | $ | 85.71 |
Crude oil and NGLs average (2) |  | $ | 72.36 |  |  | $ | 90.64 |  |  | $ | 63.71 |
Natural gas ($/Mcf) (1) (3) |  |  |  |  |  |
North America |  | $ | 3.04 |  |  | $ | 6.51 |  |  | $ | 4.05 |
International average |  | $ | 12.81 |  |  | $ | 12.78 |  |  | $ | 6.21 |
North Sea |  | $ | 10.45 |  |  | $ | 15.75 |  |  | $ | 2.94 |
Offshore Africa |  | $ | 13.19 |  |  | $ | 12.23 |  |  | $ | 7.17 |
Natural gas average |  | $ | 3.10 |  |  | $ | 6.55 |  |  | $ | 4.07 |
Average ($/BOE) (1) (2) |  | $ | 50.54 |  |  | $ | 70.07 |  |  | $ | 49.67 |

(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as crude oil and NGLs sales and natural gas sales divided by respective sales volumes.
North America
North America realized crude oil and NGLs prices decreased 20% to average $70.51 per bbl for 2023 from $88.43 per bbl for 2022 (2021 – $62.10 per bbl), primarily due to lower WTI benchmark pricing.
The Company continues to focus on its crude oil blending marketing strategy including a blending strategy that expands markets within current pipeline infrastructure, supporting pipeline projects that will provide capacity to transport crude oil to new markets, and working with refiners to add incremental heavy crude oil and bitumen (thermal oil) conversion capacity. During 2023, the Company contributed approximately 217,000 bbl/d of heavy crude oil blends to the WCS stream.
The Company has 20-year transportation agreements to ship 94,000 bbl/d of crude oil on the Trans Mountain Pipeline Expansion that will provide waterborne access to international markets. The expansion is nearing completion and Trans Mountain Corporation targets the pipeline to be operational in the second quarter of 2024.
North America realized natural gas prices decreased 53% to average $3.04 per Mcf for 2023 from $6.51 per Mcf for 2022 (2021 – $4.05 per Mcf). The decrease in realized natural gas prices for 2023 from 2022 primarily reflected lower AECO benchmark and export pricing.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:

(Yearly average) |  | 2023 |  | 2022 |  | 2021
Wellhead Price (1) |  |  |  |  |  |
Light and medium crude oil and NGLs ($/bbl) |  | $ | 70.72 |  |  | $ | 88.24 |  |  | $ | 61.29 |
Pelican Lake heavy crude oil ($/bbl) |  | $ | 77.69 |  |  | $ | 96.18 |  |  | $ | 68.05 |
Primary heavy crude oil ($/bbl) |  | $ | 75.67 |  |  | $ | 93.80 |  |  | $ | 65.88 |
Bitumen (thermal oil) ($/bbl) |  | $ | 67.62 |  |  | $ | 85.51 |  |  | $ | 60.20 |
Natural gas ($/Mcf) |  | $ | 3.04 |  |  | $ | 6.51 |  |  | $ | 4.05 |

(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.
International
International realized crude oil and NGLs prices decreased 16% to average $107.46 per bbl for 2023 from $128.41 per bbl for 2022 (2021 – $87.04 per bbl). Realized crude oil and NGLs prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The decrease in realized crude oil and NGLs prices for 2023 from 2022 reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.

Canadian Natural 2023 Annual Report | 16

P r i n c i p a l D o c u m e n t s E x h i b i t s
ROYALTIES – EXPLORATION AND PRODUCTION

|  | 2023 |  | 2022 |  | 2021
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |
North America |  | $ | 12.89 |  |  | $ | 19.64 |  |  | $ | 9.06 |
International average |  | $ | 5.99 |  |  | $ | 6.38 |  |  | $ | 1.75 |
North Sea |  | $ | 0.33 |  |  | $ | 0.30 |  |  | $ | 0.19 |
Offshore Africa |  | $ | 10.08 |  |  | $ | 11.79 |  |  | $ | 3.94 |
Crude oil and NGLs average |  | $ | 12.55 |  |  | $ | 18.91 |  |  | $ | 8.59 |
Natural gas ($/Mcf) (1) |  |  |  |  |  |
North America |  | $ | 0.13 |  |  | $ | 0.61 |  |  | $ | 0.22 |
Offshore Africa |  | $ | 0.62 |  |  | $ | 1.50 |  |  | $ | 0.33 |
Natural gas average |  | $ | 0.13 |  |  | $ | 0.61 |  |  | $ | 0.22 |
Average ($/BOE) (1) |  | $ | 7.77 |  |  | $ | 12.75 |  |  | $ | 5.98 |

(1)Calculated as royalties divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
Government royalties on a significant portion of North America crude oil and NGLs production fall under the oil sands royalty regime and are calculated on a project by project basis as a percentage of gross revenue less operating, capital and abandonment costs incurred.
North America crude oil and NGLs and natural gas royalties for 2023 and the comparable periods reflected movements in benchmark commodity prices, fluctuations in the WCS Heavy Differential and the impact of sliding scale royalty rates.
Crude oil and NGLs royalty rates (1) averaged approximately 18% of product sales for 2023, compared with 22% of product sales for 2022 (2021 – 15%). The decrease in royalty rates for 2023 from 2022 was primarily due to lower benchmark prices.
Natural gas royalty rates averaged approximately 4% of product sales for 2023, compared with 9% of product sales for 2022 (2021 – 5%). The decrease in royalty rates for 2023 from 2022 was primarily due to lower benchmark prices.
Offshore Africa
Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital expenditures and production expenses, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 9% for 2023, comparable with 9% of product sales for 2022 (2021 – 5%). Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in the various fields.
PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION

|  | 2023 |  | 2022 |  | 2021
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |
North America |  | $ | 14.46 |  |  | $ | 16.25 |  |  | $ | 13.12 |
International average |  | $ | 48.16 |  |  | $ | 51.01 |  |  | $ | 37.77 |
North Sea |  | $ | 85.57 |  |  | $ | 88.99 |  |  | $ | 54.13 |
Offshore Africa |  | $ | 21.14 |  |  | $ | 17.25 |  |  | $ | 14.73 |
Crude oil and NGLs average |  | $ | 16.12 |  |  | $ | 18.17 |  |  | $ | 14.71 |
Natural gas ($/Mcf) (1) |  |  |  |  |  |
North America |  | $ | 1.27 |  |  | $ | 1.19 |  |  | $ | 1.15 |
International average |  | $ | 7.26 |  |  | $ | 5.16 |  |  | $ | 5.07 |
North Sea |  | $ | 9.85 |  |  | $ | 9.27 |  |  | $ | 7.31 |
Offshore Africa |  | $ | 6.83 |  |  | $ | 4.40 |  |  | $ | 4.41 |
Natural gas average |  | $ | 1.30 |  |  | $ | 1.22 |  |  | $ | 1.18 |
Average ($/BOE) (1) |  | $ | 12.74 |  |  | $ | 13.76 |  |  | $ | 11.98 |

(1)Calculated as production expense divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

17 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
North America
North America crude oil and NGLs production expense for 2023 averaged $14.46 per bbl, a decrease of 11% from $16.25 per bbl for 2022 (2021 – $13.12 per bbl). The decrease in crude oil and NGLs production expense per bbl for 2023 from 2022 primarily reflected lower energy costs, partially offset by higher service costs.
North America natural gas production expense for 2023 averaged $1.27 per Mcf, an increase of 7% from $1.19 per Mcf for 2022 (2021 – $1.15 per Mcf). The increase in natural gas production expense per Mcf for 2023 from 2022 primarily reflected higher service costs.
International
International crude oil and NGLs production expense for 2023 averaged $48.16 per bbl, a decrease of 6% from $51.01 per bbl for 2022 (2021 – $37.77 per bbl). The decrease in crude oil production expense per bbl for 2023 from 2022 primarily reflected lower energy costs and the timing of liftings from various fields that have different cost structures.
ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION

($ millions, except per BOE amounts) |  | 2023 |  | 2022 |  | 2021
North America |  | $ | 3,679 |  |  | $ | 3,595 |  |  | $ | 3,569 |
North Sea |  | 494 |  |  | 1,747 |  |  | 160 |
Offshore Africa |  | 213 |  |  | 173 |  |  | 142 |
Depletion, Depreciation and Amortization |  | $ | 4,386 |  |  | $ | 5,515 |  |  | $ | 3,871 |
Less: Recoverability charge (1) (2) |  | 436 |  |  | 1,620 |  |  | — |
Adjusted depletion, depreciation and amortization (3) |  | $ | 3,950 |  |  | $ | 3,895 |  |  | $ | 3,871 |
$/BOE (4) |  | $ | 12.27 |  |  | $ | 12.45 |  |  | $ | 13.49 |

(1)As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a recoverability charge of $436 million in depletion, depreciation and amortization expense related to an increase in its estimate of future abandonment costs for the Ninian field in the North Sea.
(2)Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. As at December 31, 2022 the Company completed a recoverability assessment of its assets in the North Sea, and recognized a recoverability charge of $1,620 million in depletion, depreciation, and amortization expense following a detailed assessment which determined that the Ninian field was no longer economic.
(3)This is a non-GAAP measure used to calculate depletion, depreciation and amortization, less the impact of charges that are not related to current period normal course depletion, depreciation and amortization expense such as asset recoverability charges that are not related to current period production. It 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 financial statements (depletion, depreciation and amortization expense), as applicable, as an indication of the Company's performance.
(4)Non-GAAP ratio calculated as adjusted depletion, depreciation and amortization expense divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Adjusted depletion, depreciation and amortization expense for 2023 of $12.27 per BOE was comparable with $12.45 per BOE for 2022 (2021 – $13.49 per BOE).
Adjusted depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa.
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION

($ millions, except per BOE amounts) |  | 2023 |  | 2022 |  | 2021
North America |  | $ | 234 |  |  | $ | 171 |  |  | $ | 101 |
North Sea |  | 46 |  |  | 33 |  |  | 21 |
Offshore Africa |  | 8 |  |  | 7 |  |  | 6 |
Asset Retirement Obligation Accretion |  | $ | 288 |  |  | $ | 211 |  |  | $ | 128 |
$/BOE (1) |  | $ | 0.89 |  |  | $ | 0.67 |  |  | $ | 0.44 |

(1)Calculated as asset retirement obligation accretion divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.
Asset retirement obligation accretion expense for 2023 of $0.89 per BOE increased 33% from $0.67 per BOE for 2022 (2021 – $0.44 per BOE). The increase in asset retirement obligation accretion expense per BOE for 2023 from 2022 primarily reflected the impact of cost, inflation and timing estimates, regulatory changes, and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023.

Canadian Natural 2023 Annual Report | 18

P r i n c i p a l D o c u m e n t s E x h i b i t s
Oil Sands Mining and Upgrading
OPERATING HIGHLIGHTS
The Company continues to focus on safe, reliable and efficient operations and leveraging its technical expertise across the Horizon and AOSP sites with record SCO production in 2023 averaging 451,339 bbl/d.
The Company incurred production expense of $3,989 million for 2023, comparable with $4,076 million for 2022 (2021 – $3,414 million), reflecting the Company's continued focus on cost control and efficiencies across the entire asset base.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING

($/bbl) |  | 2023 |  | 2022 |  | 2021
Realized SCO sales price (1) |  | $ | 100.06 |  |  | $ | 117.69 |  |  | $ | 77.95 |
Bitumen value for royalty purposes (2) |  | $ | 65.43 |  |  | $ | 83.07 |  |  | $ | 58.39 |
Bitumen royalties (3) |  | $ | 14.43 |  |  | $ | 20.71 |  |  | $ | 6.62 |
Transportation (1) |  | $ | 1.89 |  |  | $ | 1.71 |  |  | $ | 1.21 |

(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)Calculated as the quarterly average of the bitumen methodology price.
(3)Calculated as royalties divided by sales volumes.
The realized SCO sales price averaged $100.06 per bbl for 2023, a decrease of 15% from $117.69 per bbl for 2022 (2021 – $77.95 per bbl). The decrease in the realized SCO sales price for 2023 compared to 2022 primarily reflected the decrease in WTI benchmark pricing.
The decrease in bitumen royalties per bbl for 2023 from 2022 primarily reflected the impact of lower prevailing bitumen pricing combined with the impact of sliding scale royalty rates.
Transportation expense averaged $1.89 per bbl for 2023, an increase of 11% from $1.71 per bbl for 2022 (2021 – $1.21 per bbl). The increase in transportation expense for 2023 from 2022 primarily reflected higher sales to the US Gulf Coast in 2023, partially offset by higher total sales volumes.
PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 22 to the Company’s audited consolidated financial statements.

($ millions) |  | 2023 |  | 2022 |  | 2021
Production expense, excluding natural gas costs |  | $ | 3,794 |  |  | $ | 3,743 |  |  | $ | 3,176 |
Natural gas costs |  | 195 |  |  | 333 |  |  | 238 |
Production expense |  | $ | 3,989 |  |  | $ | 4,076 |  |  | $ | 3,414 |

($/bbl) |  | 2023 |  | 2022 |  | 2021
Production expense, excluding natural gas costs (1) |  | $ | 23.13 |  |  | $ | 23.91 |  |  | $ | 19.45 |
Natural gas costs (2) |  | 1.19 |  |  | 2.13 |  |  | 1.46 |
Production expense (3) |  | $ | 24.32 |  |  | $ | 26.04 |  |  | $ | 20.91 |
Sales volumes (bbl/d) |  | 449,282 |  |  | 428,820 |  |  | 447,230 |

(1)Calculated as production expense, excluding natural gas costs divided by sales volumes.
(2)Calculated as natural gas costs divided by sales volumes.
(3)Calculated as production expense divided by sales volumes.
Production expense for 2023 of $24.32 per bbl decreased 7% from $26.04 per bbl for 2022 (2021 – $20.91 per bbl). The decrease in production expense per bbl for 2023 as compared to 2022 primarily reflected higher production volumes and lower energy costs.

19 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING

($ millions, except per bbl amounts) |  | 2023 |  | 2022 |  | 2021
Depletion, depreciation and amortization |  | $ | 2,011 |  |  | $ | 1,822 |  |  | $ | 1,838 |
$/bbl (1) |  | $ | 12.26 |  |  | $ | 11.64 |  |  | $ | 11.26 |

(1)Calculated as depletion, depreciation and amortization divided by sales volumes.
Depletion, depreciation and amortization expense for 2023 of $12.26 per bbl increased 5% from $11.64 per bbl for 2022 (2021 – $11.26 per bbl), reflecting the impact of a higher depletable base due to asset additions, partially offset by higher sales volumes in 2023.
ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING

($ millions, except per bbl amounts) |  | 2023 |  | 2022 |  | 2021
Asset retirement obligation accretion |  | $ | 78 |  |  | $ | 70 |  |  | $ | 57 |
$/bbl (1) |  | $ | 0.48 |  |  | $ | 0.45 |  |  | $ | 0.35 |

(1)Calculated as asset retirement obligation accretion divided by sales volumes.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.
Asset retirement obligation accretion expense for 2023 of $0.48 per bbl increased 7% from $0.45 per bbl for 2022 (2021 – $0.35 per bbl). The increase in asset retirement obligation accretion expense on a per bbl basis for 2023 from 2022 primarily reflected the impact of cost, inflation and timing estimates, and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023.
Midstream and Refining

($ millions) |  | 2023 |  | 2022 |  | 2021
Product sales |  |  |  |  |  |
Midstream activities |  | $ | 76 |  |  | $ | 80 |  |  | $ | 78 |
NWRP, refined product sales and other |  | 926 |  |  | 906 |  |  | 681 |
Segmented revenue |  | 1,002 |  |  | 986 |  |  | 759 |
Less: |  |  |  |  |  |
NWRP, refining toll |  | 303 |  |  | 247 |  |  | 213 |
Midstream activities |  | 29 |  |  | 24 |  |  | 21 |
Production expense |  | 332 |  |  | 271 |  |  | 234 |
NWRP, transportation and feedstock costs |  | 664 |  |  | 691 |  |  | 550 |
Depreciation |  | 16 |  |  | 16 |  |  | 15 |
Income from NWRP |  | — |  |  | — |  |  | (400) |
Segmented (loss) earnings |  | $ | (10) |  |  | $ | 8 |  |  | $ | 360 |

The Company's Midstream and Refining assets consist of two crude oil pipeline systems, a 50% working interest in an 84-megawatt cogeneration plant at Primrose and the Company's 50% equity investment in NWRP. Approximately 25% of the Company's crude oil production was transported to international mainline liquid pipelines via the 100% owned and operated ECHO and Pelican Lake pipelines. The Midstream pipeline asset ownership allows the Company to control transportation costs, earn third party revenue, and manage the marketing of heavy crude oils.
NWRP operates a 50,000 bbl/d bitumen upgrader and refinery that processes approximately 12,500 bbl/d (25% toll payer) of bitumen feedstock for the Company and 37,500 bbl/d (75% toll payer) of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC"), an agent of the Government of Alberta. The Company is unconditionally obligated to pay its 25% pro rata share of the debt component of the monthly fee-for-service toll over the 40-year tolling period until 2058. Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment. Production of ultra-low sulphur diesel and other refined products for 2023 averaged 81,525 BOE/d (20,381 BOE/d to the Company) (2022 – 58,351 BOE/d; 14,588 BOE/d to the Company; 2021 – 69,713 BOE/d; 17,428 BOE/d to the Company).
On June 30, 2021, the equity partners, together with the toll payers, agreed to optimize the structure of NWRP to better align the commercial interests of the equity partners and the toll payers (the "Optimization Transaction"). As a result, North West Refining Inc. transferred its entire 50% partnership interest in NWRP to APMC. The Company's 50% equity interest remained unchanged.

Canadian Natural 2023 Annual Report | 20

P r i n c i p a l D o c u m e n t s E x h i b i t s
Under the Optimization Transaction, the original term of the processing agreements was extended by 10 years from 2048 to 2058. NWRP retired higher cost subordinated debt, which carried interest rates of prime plus 6%, and issued lower cost senior secured bonds at an average rate of approximately 2.55%, reducing interest costs to NWRP and associated tolls to the toll payers. As such, NWRP repaid the Company's and APMC's subordinated debt advances of $555 million each. In addition, the Company received a $400 million distribution from NWRP during 2021.
To facilitate the Optimization Transaction, NWRP issued $500 million of 1.20% series L senior secured bonds due December 2023, $500 million of 2.00% series M senior secured bonds due December 2026, $1,000 million of 2.80% series N senior secured bonds due June 2031, and $600 million of 3.75% series O senior secured bonds due June 2051.
During 2023, NWRP repaid the $500 million of 1.20% series L senior secured bonds.
During 2023, NWRP's syndicated credit facility was reduced by $60 million to $3,115 million (2022 – $3,175 million) following the repayment and cancellation of a portion of the non-revolving credit facility that matured in June 2023. NWRP's syndicated credit facility is comprised of a $2,175 million revolving credit facility, with $118 million maturing June 2024 and the remainder maturing June 2025, and a $940 million non-revolving credit facility maturing June 2025.
As at December 31, 2023, NWRP had borrowings of $2,559 million under the syndicated credit facility (December 31, 2022 – $2,318 million) and borrowings of $77 million under its short-term demand operating facility (December 31, 2022 – $nil).
During 2022, NWRP entered into a $150 million facility to support letters of credit.
As at December 31, 2023, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $555 million (2022 – $551 million). The unrecognized equity loss from NWRP for 2023 was $4 million (2022 – recovery of unrecognized equity losses of $11 million; 2021 – unrecognized equity loss of $9 million and partnership distributions of $400 million).
Corporate and Other
ADMINISTRATION EXPENSE

($ millions, except per BOE amounts) |  | 2023 |  | 2022 |  | 2021
Expense |  | $ | 452 |  |  | $ | 415 |  |  | $ | 366 |
$/BOE (1) |  | $ | 0.93 |  |  | $ | 0.88 |  |  | $ | 0.81 |
Sales volumes (BOE/d) (2) |  | 1,331,092 |  |  | 1,285,877 |  |  | 1,233,457 |

(1)Calculated as administration expense divided by sales volumes.
(2)Total Company sales volumes.
Administration expense for 2023 of $0.93 per BOE increased 6% from $0.88 per BOE for 2022 (2021 – $0.81 per BOE). Administration expense per BOE increased from 2022 primarily due to higher personnel and corporate costs, partially offset by higher sales volumes and higher overhead recoveries.
SHARE-BASED COMPENSATION

($ millions) |  | 2023 |  | 2022 |  | 2021
Share-based compensation expense |  | $ | 491 |  |  | $ | 804 |  |  | $ | 514 |

The Company’s Stock Option Plan provides employees with the right to receive common shares or a cash payment in exchange for stock options surrendered. The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined with reference to the value of the Company's shares, and by individual employee performance and the extent to which certain other performance measures are met.
The Company recognized $491 million of share-based compensation expense for 2023, primarily as a result of the measurement of the fair value of outstanding stock options related to the impact of normal course graded vesting of stock options granted in prior periods, the impact of vested stock options exercised or surrendered during the period, and changes in the Company’s share price. An expense of $70 million related to PSUs granted to certain executive employees was included in the share-based compensation expense for 2023 (2022 – $101 million expense; 2021 – $79 million expense).

21 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
INTEREST AND OTHER FINANCING EXPENSE

($ millions, except effective interest rate) |  | 2023 |  | 2022 |  | 2021
Interest and other financing expense |  | $ | 636 |  |  | $ | 549 |  |  | $ | 711 |
Less: Interest income and other (1) |  | (55) |  |  | (121) |  |  | (32) |
Interest on long-term debt and lease liabilities (1) |  | $ | 691 |  |  | $ | 670 |  |  | $ | 743 |
Average current and long-term debt (2) |  | $ | 12,749 |  |  | $ | 13,986 |  |  | $ | 18,935 |
Average lease liabilities (2) |  | 1,500 |  |  | 1,531 |  |  | 1,619 |
Average long-term debt and lease liabilities (2) |  | $ | 14,249 |  |  | $ | 15,517 |  |  | $ | 20,554 |
Average effective interest rate (3) (4) |  | 4.8% |  | 4.3% |  | 3.5%
Interest and other financing expense per $/BOE (5) |  | $ | 1.31 |  |  | $ | 1.17 |  |  | $ | 1.58 |
Sales volumes (BOE/d) (6) |  | 1,331,092 |  |  | 1,285,877 |  |  | 1,233,457 |

(1)Item is a component of interest and other financing expense.
(2)The average of current and long-term debt and lease liabilities outstanding during the respective year.
(3)This is a non-GAAP ratio and 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 audited consolidated financial statements, as applicable, as an indication of the Company's performance.
(4)Calculated as the average interest on long-term debt and lease liabilities divided by the average long-term debt and lease liabilities balance for the respective year. The Company presents its average effective interest rate for financial statement users to evaluate the Company’s average cost of debt borrowings.
(5)Calculated as interest and other financing expense divided by sales volumes.
(6)Total Company sales volumes.
Interest and other financing expense per BOE for 2023 increased 12% to $1.31 per BOE from $1.17 per BOE for 2022 (2021 – $1.58 per BOE). The increase in interest and other financing expense per BOE for 2023 from 2022 primarily reflected the impact of higher interest rates on floating rate long-term debt, together with the impact of higher accrued interest income on the deferred PRT recovery in 2022, partially offset by lower average debt levels in 2023.
The Company’s average effective interest rate of 4.8% for 2023 increased from 4.3% for 2022 primarily due to higher prevailing interest rates on floating rate debt held during 2023.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes.

($ millions) |  | 2023 |  | 2022 |  | 2021
Foreign currency contracts |  | $ | (17) |  |  | $ | (37) |  |  | $ | 1 |
Natural gas financial instruments (1) (2) |  | 3 |  |  | 13 |  |  | 17 |
Crude oil and NGLs financial instruments (1) |  | — |  |  | 17 |  |  | (1) |
Net realized (gain) loss |  | (14) |  |  | (7) |  |  | 17 |
Foreign currency contracts |  | (9) |  |  | (16) |  |  | 6 |
Natural gas financial instruments (1) (2) |  | 21 |  |  | (10) |  |  | 11 |
Crude oil and NGLs financial instruments (1) |  | — |  |  | (2) |  |  | 2 |
Net unrealized loss (gain) |  | 12 |  |  | (28) |  |  | 19 |
Net (gain) loss |  | $ | (2) |  |  | $ | (35) |  |  | $ | 36 |

(1)Commodity financial instruments were assumed in the acquisition of Storm Resources Ltd. ("Storm") in 2021, and Painted Pony Energy Ltd. ("Painted Pony") in 2020.
(2)In the fourth quarter of 2023, the Company entered into 50,000 MMBtu/d of US$1.82 AECO fixed price financial hedge contracts for the period of January to December 2024.
During 2023, net realized risk management gains were related to the settlement of foreign currency contracts, partially offset by losses on natural gas financial instruments. The Company recorded a net unrealized loss of $12 million ($7 million after-tax of $5 million) on its risk management activities for 2023 (2022 – $28 million unrealized gain, $25 million after-tax of $3 million; 2021 – $19 million unrealized loss, $16 million after-tax of $3 million).
Further details related to outstanding derivative financial instruments as at December 31, 2023 are disclosed in note 19 to the Company's audited consolidated financial statements.

Canadian Natural 2023 Annual Report | 22

P r i n c i p a l D o c u m e n t s E x h i b i t s
FOREIGN EXCHANGE

($ millions) |  | 2023 |  | 2022 |  | 2021
Net realized (gain) loss |  | $ | (19) |  |  | $ | (114) |  |  | $ | 78 |
Net unrealized (gain) loss |  | (260) |  |  | 852 |  |  | (205) |
Net (gain) loss (1) |  | $ | (279) |  |  | $ | 738 |  |  | $ | (127) |

(1)Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange gain for 2023 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The net unrealized foreign exchange gain for 2023 was primarily related to the impact of a stronger Canadian dollar with respect to outstanding US dollar debt. The US/Canadian dollar exchange rate at December 31, 2023 was US$0.7573 (December 31, 2022 – US$0.7389, December 31, 2021 – US$0.7901).
INCOME TAXES

($ millions, except effective tax rates) |  | 2023 |  | 2022 |  | 2021
North America (1) |  | $ | 1,853 |  |  | $ | 2,789 |  |  | $ | 1,841 |
North Sea |  | (6) |  |  | 69 |  |  | 7 |
Offshore Africa |  | 73 |  |  | 74 |  |  | 21 |
Current PRT – North Sea |  | (58) |  |  | (42) |  |  | (34) |
Other taxes |  | 17 |  |  | 16 |  |  | 13 |
Current income tax |  | 1,879 |  |  | 2,906 |  |  | 1,848 |
Deferred corporate income tax |  | 267 |  |  | 302 |  |  | 399 |
Deferred PRT – North Sea |  | (214) |  |  | (441) |  |  | — |
Deferred income tax |  | 53 |  |  | (139) |  |  | 399 |
Income tax |  | $ | 1,932 |  |  | $ | 2,767 |  |  | $ | 2,247 |
Earnings before taxes |  | $ | 10,165 |  |  | $ | 13,704 |  |  | $ | 9,911 |
Effective tax rate on net earnings (2) |  | 19% |  | 20% |  | 23%
($ millions, except effective tax rates) |  | 2023 |  | 2022 |  | 2021
Income tax |  | $ | 1,932 |  |  | $ | 2,767 |  |  | $ | 2,247 |
Tax effect on non-operating items (3) |  | 345 |  |  | 964 |  |  | 5 |
Current PRT – North Sea |  | 58 |  |  | 42 |  |  | 34 |
Deferred PRT – North Sea |  | 9 |  |  | — |  |  | — |
Other taxes |  | (17) |  |  | (16) |  |  | (13) |
Effective tax on adjusted net earnings |  | $ | 2,327 |  |  | $ | 3,757 |  |  | $ | 2,273 |
Adjusted net earnings from operations (4) |  | $ | 8,533 |  |  | $ | 12,863 |  |  | $ | 7,420 |
Adjusted net earnings from operations, before taxes |  | $ | 10,860 |  |  | $ | 16,620 |  |  | $ | 9,693 |
Effective tax rate on adjusted net earnings from operations (5) (6) |  | 21% |  | 23% |  | 23%

(1)Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.
(2)Calculated as total of current and deferred income tax divided by earnings before taxes.
(3)Includes the net income tax effect on PSUs, unrealized risk management, and government grant income related to abandonment expenditures in 2022, as well as deferred PRT and income tax recoveries related to the recoverability charges recognized in 2023 and 2022.
(4)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(5)This is a non-GAAP ratio and 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 financial statements, as applicable, as an indication of the Company's performance.
(6)Calculated as effective tax on adjusted net earnings divided by adjusted net earnings from operations, before taxes. The Company presents its effective tax rate on adjusted net earnings from operations for financial statement users to evaluate the Company's effective tax rate on its core business activities.
The effective tax rate on net earnings and adjusted net earnings from operations for 2023 and the comparable years included the impact of non-taxable items in North America and the North Sea and the impact of differences in jurisdictional income and tax rates in the countries in which the Company operates, in relation to net earnings.
The current and deferred corporate income tax and current and deferred PRT in the North Sea in 2023 and 2022 included the impact of carrybacks of PRT losses, including expenditures related to decommissioning activities at the Company's platforms in the North Sea. Deferred PRT and income taxes also reflected the impact of the recoverability charges recognized in depletion, depreciation, and amortization expense for 2023 and 2022.

23 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company’s reported results of operations, financial position or liquidity.
During 2023, the Company filed Scientific Research and Experimental Development claims of approximately $380 million (2022 – $283 million; 2021 – $229 million) relating to qualifying research and development expenditures for Canadian income tax purposes.
Net Capital Expenditures (1) (2)

($ millions) |  | 2023 |  | 2022 |  | 2021
EXPLORATION AND PRODUCTION |  |  |  |  |  |
Exploration and Evaluation Assets |  |  |  |  |  |
Net expenditures |  | $ | 47 |  |  | $ | 36 |  |  | $ | 12 |
Net property dispositions |  | (3) |  |  | (3) |  |  | (11) |
Total Exploration and Evaluation Assets |  | 44 |  |  | 33 |  |  | 1 |
Property, Plant and Equipment |  |  |  |  |  |
Net property acquisitions (3) |  | 24 |  |  | 513 |  |  | 1,112 |
Well drilling, completion and equipping |  | 1,579 |  |  | 1,545 |  |  | 918 |
Production and related facilities |  | 1,267 |  |  | 1,233 |  |  | 802 |
Other |  | 61 |  |  | 59 |  |  | 64 |
Total Property, Plant and Equipment |  | 2,931 |  |  | 3,350 |  |  | 2,896 |
Total Exploration and Production |  | 2,975 |  |  | 3,383 |  |  | 2,897 |
OIL SANDS MINING AND UPGRADING |  |  |  |  |  |
Project costs |  | 348 |  |  | 294 |  |  | 236 |
Sustaining capital |  | 1,347 |  |  | 1,171 |  |  | 1,035 |
Turnaround costs |  | 189 |  |  | 287 |  |  | 145 |
Net property acquisitions (dispositions) |  | 5 |  |  | (40) |  |  | — |
Other (4) |  | 5 |  |  | 7 |  |  | 331 |
Total Oil Sands Mining and Upgrading |  | 1,894 |  |  | 1,719 |  |  | 1,747 |
Midstream and Refining |  | 10 |  |  | 9 |  |  | 9 |
Head office |  | 30 |  |  | 25 |  |  | 23 |
Net capital expenditures |  | $ | 4,909 |  |  | $ | 5,136 |  |  | $ | 4,676 |
Abandonments expenditures, net (5) |  | $ | 509 |  |  | $ | 335 |  |  | $ | 232 |
By Segment |  |  |  |  |  |
North America (3) |  | $ | 2,770 |  |  | $ | 3,133 |  |  | $ | 2,662 |
North Sea |  | 33 |  |  | 126 |  |  | 173 |
Offshore Africa |  | 172 |  |  | 124 |  |  | 62 |
Oil Sands Mining and Upgrading |  | 1,894 |  |  | 1,719 |  |  | 1,747 |
Midstream and Refining |  | 10 |  |  | 9 |  |  | 9 |
Head office |  | 30 |  |  | 25 |  |  | 23 |
Net capital expenditures |  | $ | 4,909 |  |  | $ | 5,136 |  |  | $ | 4,676 |

(1)Net capital expenditures exclude the impact of lease assets and fair value and revaluation adjustments, and include non-cash transfers of property, plant and equipment to inventory due to change in use.
(2)Non-GAAP Financial Measure. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Includes cash consideration of $771 million and the settlement of long-term debt of $183 million assumed in the acquisition of Storm in 2021.
(4)Includes the acquisition of a 5% net carried interest on an existing oil sands lease in 2021.
(5)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural 2023 Annual Report | 24

P r i n c i p a l D o c u m e n t s E x h i b i t s
The Company's strategy is focused on building a diversified asset base that is balanced among various products. In order to facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production expenses.
Net capital expenditures for 2023 were $4,909 million compared with $5,136 million for 2022. Net capital expenditures for 2023 included base capital expenditures (1) of $3,958 million and strategic growth capital expenditures (1) of $925 million, in accordance with the Company's capital budget. In addition, the Company reported abandonment expenditures (2) of $509 million for the year ended December 31, 2023 compared with $335 million for the year ended December 31, 2022.
2024 CAPITAL BUDGET
On December 14, 2023, the Company announced its 2024 capital budget targeted at approximately $5,420 million, and targeting to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024.
The 2024 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
DRILLING ACTIVITY (1) (2)

(number of net wells) |  | 2023 |  | 2022 |  | 2021
Net successful crude oil wells (3) |  | 221 |  |  | 317 |  |  | 149 |
Net successful natural gas wells |  | 61 |  |  | 72 |  |  | 49 |
Dry wells |  | 2 |  |  | 1 |  |  | 1 |
Total |  | 284 |  |  | 390 |  |  | 199 |
Success rate |  | 99% |  | 99% |  | 99%

(1)Includes drilling activity for North America and International segments.
(2)In addition, during 2023, on a net basis, the Company drilled 334 stratigraphic and 11 service wells in the Oil Sands Mining and Upgrading segment, 24 stratigraphic and 48 service wells in the Company's thermal oil projects, and 2 service wells in the Northern Plains region.
(3)Includes bitumen wells.
North America
During 2023, the Company drilled 61 net natural gas wells, 132 net primary heavy crude oil wells, 2 net Pelican Lake heavy crude oil wells, 50 net bitumen (thermal oil) wells and 39 net light crude oil wells.
(1)Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on net capital expenditures.
(2)A reconciliation of abandonment expenditures and abandonment expenditures, net is presented in the "Non-GAAP and Other Financial Measures" section of this MD&A.

25 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
Liquidity and Capital Resources

($ millions, except ratios) |  | 2023 |  | 2022 |  | 2021
Adjusted working capital (1) |  | $ | 712 |  |  | $ | (1,190) |  |  | $ | (480) |
Long-term debt, net (2) |  | $ | 9,922 |  |  | $ | 10,525 |  |  | $ | 13,950 |
Shareholders’ equity |  | $ | 39,832 |  |  | $ | 38,175 |  |  | $ | 36,945 |
Debt to book capitalization (2) |  | 20% |  | 22% |  | 27%
After-tax return on average capital employed (3) |  | 17% |  | 22% |  | 16%

(1)Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(2)Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
As at December 31, 2023, the Company's capital resources consisted primarily of cash flows from operating activities, available bank credit facilities and access to debt capital markets. Cash flows from operating activities and the Company’s ability to renew existing bank credit facilities and raise new debt are dependent on factors discussed in the "Business Environment" section and in the "Risks and Uncertainties" section of this MD&A. In addition, the Company's ability to renew existing bank credit facilities and raise new debt reflects current credit ratings as determined by independent rating agencies, and market conditions. The Company continues to believe its internally generated cash flows from operating activities, supported by the implementation of its ongoing hedge policy, the flexibility of its capital expenditure programs and multi-year financial plans, its existing bank credit facilities, and its ability to raise new debt on commercially acceptable terms will provide sufficient liquidity to sustain its operations in the short, medium and long-term and support its growth strategy.
On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by:
▪Monitoring cash flows from operating activities, which is the primary source of funds;
▪Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place, and as applicable, taking other mitigating actions to minimize the impact in the event of a default;
▪Actively managing the allocation of maintenance and growth capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. The Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt;
▪Monitoring the Company's ability to fulfill financial obligations as they become due or the ability to monetize assets in a timely manner at a reasonable price;
▪Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages; and
▪Reviewing the Company's borrowing capacity:
◦During 2022, the Company repaid and cancelled its $500 million non-revolving portion of the $1,000 million term credit facility, reducing the remaining facility to the $500 million revolving credit facility maturing February 2023, and extended this facility from February 2023 to February 2024. During 2023, the Company extended its $500 million revolving credit facility from February 2024 to February 2025.
◦During 2023, the Company extended its $2,425 million revolving syndicated credit facility originally maturing June 2024 to June 2027.
◦The revolving syndicated credit facilities are extendible annually at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal would be repayable on the maturity date. Borrowings under the Company's revolving term credit facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers' acceptances, SOFR, US base rate or Canadian prime rate.
◦During 2022, the Company discontinued its £5 million demand credit facility related to its North Sea operations.
◦The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million.
◦During 2023, the Company repaid $405 million of 1.45% medium-term notes.
◦During 2022, the Company repaid through market purchases $498 million of medium-term notes with interest rates ranging from 1.45% to 3.55%, originally due between 2023 and 2028.
◦During 2022, the Company repaid $1,000 million of 3.31% medium-term notes.

Canadian Natural 2023 Annual Report | 26

P r i n c i p a l D o c u m e n t s E x h i b i t s
◦During 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada, which expires in August 2025, replacing the Company's previous base shelf prospectus which would have expired in August 2023. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.
◦During 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023.
◦During 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States, which expires in August 2025, replacing the Company's previous base shelf prospectus which would have expired in August 2023. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.
As at December 31, 2023, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,852 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. At December 31, 2023, the Company had no commercial paper drawn under its commercial paper program and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
During 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the US$1,100 million 6.25% US dollar debt securities due March 2038. The Company realized cash proceeds of $158 million on settlement. As at December 31, 2023, the Company had no cross currency swap contracts outstanding. As at December 31, 2023, there were no foreign currency contracts designated as cash flow hedges.
Long-term debt, net was $9,922 million at December 31, 2023, resulting in a debt to book capitalization ratio (1) of 20% (December 31, 2022 – 22%, December 31, 2021 – 27%); this ratio was below the 25% to 45% internal range utilized by management. The ratio may fall below or exceed the targeted range depending on the timing of acquisitions, the execution of the Company's capital program, and commodity price and foreign currency volatility.
The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Further details related to the Company’s long-term debt at December 31, 2023 are discussed in note 11 to the Company’s audited consolidated financial statements. The Company is subject to a financial covenant that requires debt to book capitalization as defined in its credit facility agreements to not exceed 65%. As at December 31, 2023, the Company was in compliance with this covenant.
The Company periodically utilizes commodity derivative financial instruments under its commodity hedge policy to reduce the risk of volatility in commodity prices and to support the Company’s cash flow for its capital expenditure programs. This policy currently allows for the hedging of up to 60% of the near 12 months budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this policy, the purchase of put options is in addition to the above parameters. Further details related to the Company’s commodity derivative financial instruments outstanding at December 31, 2023 are discussed in note 19 to the Company’s audited consolidated financial statements.
As at December 31, 2023, the maturity dates of long-term debt and other long-term liabilities and related interest payments were as follows:

| Less than 1 year |  | 1 to less than 2 years |  | 2 to less than 5 years |  | Thereafter
Long-term debt (1) | $ | 980 |  |  | $ | 1,584 |  |  | $ | 2,317 |  |  | $ | 5,978 |
Other long-term liabilities (2) | $ | 302 |  |  | $ | 184 |  |  | $ | 428 |  |  | $ | 645 |
Interest and other financing expense (3) | $ | 582 |  |  | $ | 518 |  |  | $ | 1,257 |  |  | $ | 3,362 |

(1)Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
(2)Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $298 million; one to less than two years, $184 million; two to less than five years, $428 million; and thereafter, $645 million.
(3)Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates as at December 31, 2023.
(1)Capital management measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

27 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
SHARE CAPITAL
As at December 31, 2023, there were 1,072,408,000 common shares outstanding (December 31, 2022 – 1,102,636,000 common shares) and 26,205,000 stock options outstanding (December 31, 2022 – 31,150,000 common shares). As at February 27, 2024, the Company had 1,070,845,000 common shares outstanding and 28,296,000 stock options outstanding.
On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $1.05 per common share, beginning with the dividend payable on April 5, 2024.
On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $1.00 per common share. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share. On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share. On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share. On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share. On November 3, 2021, the Board of Directors approved a 25% increase in the quarterly dividend to $0.5875 per common share. On March 3, 2021, the Board of Directors approved an 11% increase in the quarterly dividend to $0.47 per common share, from $0.425 per common share. The dividend policy undergoes periodic review by the Board of Directors and is subject to change.
On March 8, 2023, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange, alternative Canadian trading platforms, and the New York Stock Exchange, up to 92,296,006 common shares, representing 10% of the public float, over a 12-month period commencing March 13, 2023 and ending March 12, 2024.
During 2023, the Company purchased 40,050,000 common shares at a weighted average price of $82.86 per common share for a total cost of $3,318 million. Retained earnings were reduced by $2,929 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2023, up to and including February 27, 2024, the Company purchased 4,000,000 common shares at a weighted average price of $85.54 per common share for a total cost of $342 million.
On February 28, 2024, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, the purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
Share Split
On February 28, 2024, the Company's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval and the Company having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company's Annual and Special Meeting of Shareholders to be held on May 2, 2024.
Commitments and Contingencies
In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company’s commitments as at December 31, 2023:

($ millions) | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter
Product transportation and processing (1) | $ | 1,572 |  | $ | 1,595 |  | $ | 1,408 |  | $ | 1,358 |  | $ | 1,242 |  | $ | 13,380 |
North West Redwater Partnership service toll (2) | $ | 158 |  | $ | 157 |  | $ | 139 |  | $ | 126 |  | $ | 130 |  | $ | 4,985 |
Offshore vessels and equipment | $ | 36 |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | — |
Field equipment and power | $ | 38 |  | $ | 25 |  | $ | 23 |  | $ | 22 |  | $ | 22 |  | $ | 193 |
Other | $ | 145 |  | $ | 111 |  | $ | 112 |  | $ | 25 |  | $ | 26 |  | $ | 355 |

(1)The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Pipeline Expansion reflects interim tolls approved by the Canada Energy Regulator in the fourth quarter of 2023, and is subject to change pending the approval of final tolls.
(2)Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in the toll is $3,011 million of interest payable over the 40-year tolling period, ending in 2058.
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of its various development projects. These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position.

Canadian Natural 2023 Annual Report | 28

P r i n c i p a l D o c u m e n t s E x h i b i t s
Reserves
For the years ended December 31, 2023 and 2022, the Company retained Independent Qualified Reserves Evaluators to evaluate and review all of the Company’s total proved and total proved plus probable reserves. The evaluation and review was 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 following are reconciliation tables of the Company gross total proved and total proved plus probable reserves using forecast prices and costs as at the effective date of December 31, 2023:

Total Proved | Light and Medium Crude Oil |  | Primary Heavy Crude Oil |  | Pelican Lake Heavy Crude Oil |  | Bitumen (Thermal Oil) |  | Synthetic Crude Oil |  | Natural Gas |  | Natural Gas Liquids |  | Barrels of Oil Equivalent
| (MMbbl) |  | (MMbbl) |  | (MMbbl) |  | (MMbbl) |  | (MMbbl) |  | (Bcf) |  | (MMbbl) |  | (MMBOE)
December 31, 2022 (1) | 231 |  |  | 179 |  |  | 262 |  |  | 3,284 |  |  | 6,873 |  |  | 13,627 |  |  | 486 |  |  | 13,587 |
Discoveries | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 5 |  |  | — |  |  | 1 |
Extensions | 18 |  |  | 22 |  |  | — |  |  | 68 |  |  | 191 |  |  | 1,246 |  |  | 43 |  |  | 548 |
Infill Drilling | 8 |  |  | 6 |  |  | — |  |  | — |  |  | — |  |  | 638 |  |  | 35 |  |  | 156 |
Improved Recovery | — |  |  | — |  |  | 1 |  |  | 6 |  |  | 34 |  |  | — |  |  | — |  |  | 40 |
Acquisitions | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Dispositions | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (7) |  |  | (1) |  |  | (2) |
Economic Factors | 1 |  |  | 1 |  |  | 1 |  |  | 1 |  |  | — |  |  | (81) |  |  | (2) |  |  | (12) |
Technical Revisions | (12) |  |  | 13 |  |  | 12 |  |  | 24 |  |  | (23) |  |  | 362 |  |  | 3 |  |  | 77 |
Production | (27) |  |  | (28) |  |  | (17) |  |  | (96) |  |  | (165) |  |  | (785) |  |  | (22) |  |  | (486) |
December 31, 2023 (1) | 218 |  |  | 193 |  |  | 258 |  |  | 3,287 |  |  | 6,910 |  |  | 15,005 |  |  | 543 |  |  | 13,910 |

Total Proved Plus Probable | Light and Medium Crude Oil |  | Primary Heavy Crude Oil |  | Pelican Lake Heavy Crude Oil |  | Bitumen (Thermal Oil) |  | Synthetic Crude Oil |  | Natural Gas |  | Natural Gas Liquids |  | Barrels of Oil Equivalent
| (MMbbl) |  | (MMbbl) |  | (MMbbl) |  | (MMbbl) |  | (MMbbl) |  | (Bcf) |  | (MMbbl) |  | (MMBOE)
December 31, 2022 (1) | 320 |  |  | 272 |  |  | 376 |  |  | 5,186 |  |  | 7,408 |  |  | 22,270 |  |  | 772 |  |  | 18,046 |
Discoveries | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 7 |  |  | 1 |  |  | 2 |
Extensions | 28 |  |  | 37 |  |  | — |  |  | 97 |  |  | 209 |  |  | 2,009 |  |  | 74 |  |  | 780 |
Infill Drilling | 12 |  |  | 8 |  |  | — |  |  | — |  |  | — |  |  | 962 |  |  | 48 |  |  | 227 |
Improved Recovery | — |  |  | — |  |  | 1 |  |  | 7 |  |  | 51 |  |  | — |  |  | — |  |  | 58 |
Acquisitions | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Dispositions | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (8) |  |  | (1) |  |  | (2) |
Economic Factors | 1 |  |  | 1 |  |  | 1 |  |  | 1 |  |  | — |  |  | (88) |  |  | (2) |  |  | (12) |
Technical Revisions | (28) |  |  | (2) |  |  | 4 |  |  | (4) |  |  | (43) |  |  | (83) |  |  | (21) |  |  | (108) |
Production | (27) |  |  | (28) |  |  | (17) |  |  | (96) |  |  | (165) |  |  | (785) |  |  | (22) |  |  | (486) |
December 31, 2023 (1) | 305 |  |  | 288 |  |  | 365 |  |  | 5,191 |  |  | 7,460 |  |  | 24,284 |  |  | 848 |  |  | 18,504 |

(1)Information in the reserves data tables may not add due to rounding. BOE values as presented may not calculate due to rounding.
At December 31, 2023, the total proved crude oil, bitumen (thermal oil) and NGLs reserves were 11,409 MMbbl, and total proved plus probable crude oil, bitumen (thermal oil) and NGLs reserves were 14,457 MMbbl. Total proved reserves additions and revisions replaced 126% of 2023 production. Additions to total proved reserves resulting from exploration and development activities, acquisitions, dispositions and future offset additions amounted to 430 MMbbl, and additions to total proved plus probable reserves amounted to 570 MMbbl. Net positive revisions amounted to 18 MMbbl for total proved reserves and net negative revisions amounted to 92 MMbbl for total proved plus probable reserves, primarily due to technical revisions.
At December 31, 2023, the total proved natural gas reserves were 15,005 Bcf, and total proved plus probable natural gas reserves were 24,284 Bcf. Total proved reserves additions and revisions replaced 275% of 2023 production. Additions to total proved reserves resulting from exploration and development activities, acquisitions, dispositions and future offset additions amounted to 1,882 Bcf, and additions to total proved plus probable reserves amounted to 2,970 Bcf.
Net positive revisions amounted to 280 Bcf for total proved reserves, primarily due to technical revisions. Net negative revisions amounted to 171 Bcf for total proved plus probable reserves, primarily due to economic factors and technical revisions.

29 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
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 Independent Qualified Reserves Evaluators to review the qualifications of and procedures used by each evaluator in determining the estimate of the Company’s quantities and related net present value of future net revenue of the remaining reserves. Additional reserves information is annually disclosed in the AIF.
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 FASB 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 annual report.
Risks and Uncertainties
The Company is exposed to various operational risks inherent in the exploration, development, production and marketing of crude oil and NGLs and natural gas and the mining, extracting and upgrading of bitumen into SCO. These inherent risks include, but are not limited to, the following:
▪Volatility in the prevailing prices of crude oil and NGLs, natural gas and refined products;
▪The ability to find, produce and replace reserves, whether sourced from exploration, improved recovery or acquisitions, at a reasonable cost, including the risk of reserves revisions due to economic and technical factors. Reserves revisions can have a positive or negative impact on asset valuations, ARO and depletion rates;
▪Reservoir quality and uncertainty of reserves estimates;
▪Regulatory risk related to approval for exploration and development activities, which can add to costs or cause delays in projects;
▪Labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective manner;
▪Operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting and upgrading the Company’s bitumen products;
▪Timing and success of integrating the business and operations of acquired companies and assets;
▪Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts, including derivative financial instruments and physical sales contracts as part of a hedging program;
▪Interest rate risk associated with the Company’s ability to secure financing on commercially acceptable terms;
▪Foreign exchange risk due to the effect of fluctuating exchange rates on the Company’s US dollar denominated debt and revenue from sales predominantly based on US dollar denominated benchmarks;
▪Environmental impact risk associated with exploration and development activities, including GHG;
▪Future legislative and regulatory developments related to environmental regulation, including but not limited to GHG compliance costs and reduction targets;
▪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 decarbonisation policies;
▪Potential actions of governments, regulatory authorities and other stakeholders that may result in costs or restrictions in the jurisdictions where the Company has operations, including but not limited to restrictions on production and the certainty and timelines for regulatory processes;
▪Geopolitical risks associated with changing governments or governmental policies, social instability and other political, economic or diplomatic developments in the regions where the Company has its operations;
▪Changing royalty regimes;
▪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 and other factors;
▪The access to markets for the Company’s products;
▪The risk of significant interruption or failure of the Company's information technology systems and related data and control systems or a significant breach that could adversely affect the Company's operations;
▪Business interruptions because of unexpected events such as fires or explosions whether caused by human error or nature, severe storms and other calamitous acts of nature, blowouts, freeze-ups, mechanical or equipment failures of facilities and infrastructure and other similar events affecting the Company or other parties whose operations or assets directly or indirectly impact the Company and that may or may not be financially recoverable;

Canadian Natural 2023 Annual Report | 30

P r i n c i p a l D o c u m e n t s E x h i b i t s
▪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 manpower resulting from quarantines that affect the Company’s labour pools in the 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 (as was the case with the COVID-19 pandemic). Depending on the severity, a large scale epidemic or pandemic could impact international demand for commodities and have a corresponding impact on the prices realized by the Company, which could have a material adverse effect on the Company's financial condition;
▪Liquidity risk related to the Company's ability to fulfill financial obligations as they become due or ability to liquidate assets in a timely manner at a reasonable price; and
▪Other circumstances affecting revenue and expenses.
The Company uses a variety of means to seek to mitigate and/or minimize these risks. The Company maintains a comprehensive property loss and business interruption insurance program to reduce risk. Operational control is enhanced by focusing efforts on large core areas with high working interests and by assuming operatorship of key facilities. Product mix is diversified, consisting of the production of natural gas and the production of crude oil of various grades and NGLs. The Company believes this diversification reduces price risk when compared with over-leverage to one commodity. Accounts receivable from the sale of crude oil and natural gas are mainly with customers in the crude oil and natural gas industry and are subject to normal industry credit risks. The Company seeks to manage these risks by monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place, and as applicable, taking other mitigating actions to minimize the impact in the event of a default. Derivative financial instruments are periodically utilized to help ensure targets are met and to manage commodity price, foreign currency and interest rate exposures. The Company is exposed to possible losses in the event of non-performance by counterparties to derivative financial instruments; however, the Company seeks to manage this credit risk by entering into agreements with counterparties that are substantially all investment grade financial institutions. The arrangements and policies concerning the Company’s financial instruments are under constant review and may change depending upon the prevailing market conditions. Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital, consisting primarily of cash flow from operating activities, available credit facilities, commercial paper and access to debt capital markets, to meet obligations as they become due. The Company has implemented cyber security protocols and procedures designed to reduce the risk of failure or a significant breach of the Company’s information technology systems and related data and control systems.
The Company has safety, integrity and environmental management systems to recover and process crude oil and natural gas resources safely, efficiently, and in an environmentally sustainable manner and mitigate risk.
The Company’s capital structure mix is also monitored on a continual basis to ensure that it optimizes flexibility, minimizes cost and offers the greatest opportunity for growth. This includes the determination of a reasonable level of debt and any interest rate exposure risk that may exist.
For additional details regarding the Company’s risks and uncertainties, refer to the Company’s AIF for the year ended December 31, 2023.
Environment
The Company has a Corporate Statement on Environmental Management which affirms that environmental stewardship is a fundamental value of the Company. The Company continues to invest in people, proven and new technologies, facilities and infrastructure to recover and process crude oil and natural gas resources efficiently and in an environmentally responsible and sustainable manner. Environmental, social, economic and health considerations are evaluated in new project designs and in operations to improve environmental performance. Processes are employed to avoid, mitigate, minimize or compensate for environmental effects. When working with local communities, the Company considers the interests and values of the people using the land in proximity to its operations, and where appropriate, adapts projects to recognize those matters.
The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulation compliance, particularly in North America and the North Sea. Existing and expected legislation and regulations may require the Company to address and mitigate the effect of its activities on the environment. 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 budget to continue to meet current environmental protection requirements; however there are no assurances that the effect of future environmental laws and regulations will not be significant to the Company's business, financial condition and results of operations. Increasingly stringent laws and regulations may have an adverse effect on the Company’s future net earnings.
The Company’s associated environmental risk management strategies incorporate working constructively with legislators and regulators on any new or revised policies, legislation or regulations to reflect a balanced approach to sustainable development. Specific measures in response to existing or new legislation include a focus on the Company’s energy efficiency, air emissions management, water management and land management to minimize disturbance impacts. The Company’s environmental risk management strategies employ an Environmental Management Plan (the "Plan").

31 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
As part of risk management, the Company develops, assesses and implements technologies and innovative practices that will improve environmental performance, often through collaborative efforts with industry partners, governments and research institutions. Details of the Plan, along with performance results, are presented to, and reviewed by, the Board of Directors quarterly.
The Plan and the Company's operating guidelines focus on minimizing the 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. Training and due diligence for operators and contractors is key to the effectiveness of the Company’s environmental management programs and the prevention of incidents to protect the environment. The Company, as part of this Plan, has implemented proactive programs that include:
▪Environmental planning to assess potential impacts and implement avoidance and mitigation programs in order to maintain biodiversity for terrestrial and aquatic systems and high value ecosystems;
▪Continued evaluation of new technologies to reduce environmental impacts, including support for Canada’s Oil Sands Innovation Alliance ("COSIA"), the innovation arm of Pathways, Petroleum Technology Alliance Canada ("PTAC") and other research institutions;
▪Mitigation of the Company's climate change impacts through implementation of various CO 2 emissions reduction and carbon capture projects including: CO 2 injection for EOR, CO 2 injection in tailings and the Quest Carbon Capture and Storage Facility; a methane emissions reduction program, including solution gas conservation to reduce methane venting, and an equipment retrofit program to reduce methane emissions from pneumatic equipment; and optimization of efficiencies at the Company’s facilities;
▪Water programs to improve efficiency of use and recycle rates as well as to reduce fresh water use;
▪Groundwater monitoring for all thermal in situ and mine operations;
▪Effective reclamation and decommissioning programs across the Company’s operations. In North America, well abandonment and progressive reclamation of large contiguous areas of land provides the foundation for the enhancement of biodiversity and functional wildlife habitats. In the Company's International operations, decommissioning activities continued for the Banff and Kyle fields and planning commenced for decommissioning of the Ninian Hub area;
▪Tailings management in Oil Sands Mining to minimize fine tailings and promote progressive reclamation;
▪Monitoring programs to assess changes to biodiversity, wildlife and fisheries in order to manage construction and operation effects and to assess reclamation success;
▪Participation and support for the Oil Sands Monitoring Program of regional important resources;
▪An active spill prevention and management program;
▪Supporting regional air shed monitoring for emissions and their deposition; and
▪An internal environmental management system for compliance audit and inspection programs of operating facilities.
The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and have been discounted using a weighted average discount rate of 5.2% (2022 – 5.6%; 2021 – 4.0%). For 2023, the Company’s capital expenditures included $509 million for abandonment expenditures (2022 – $449 million; 2021 – $307 million). Refer to the “Non-GAAP and Other Financial Measures” section of this MD&A for further details on abandonments expenditures, net. The Company’s estimated discounted ARO at December 31, 2023 was as follows:

($ millions) | 2023 |  | 2022
Exploration and Production |  |  |
North America | $ | 4,471 |  |  | $ | 4,326 |
North Sea | 1,441 |  |  | 1,011 |
Offshore Africa | 165 |  |  | 143 |
Oil Sands Mining and Upgrading | 1,612 |  |  | 1,427 |
Midstream and Refining | 1 |  |  | 1 |
| $ | 7,690 |  |  | $ | 6,908 |

The discounted ARO was based on estimates of future costs to abandon and restore wells, production facilities, mine sites, upgrading facilities and tailings, and offshore production platforms.
Factors that affect costs include number of wells drilled, well depth, facility size and the specific environmental legislation. The estimated future costs are based on estimates of current costs in accordance with present legislation, industry operating practice as well as the expected work scope and the timing of abandonment.

Canadian Natural 2023 Annual Report | 32

P r i n c i p a l D o c u m e n t s E x h i b i t s
In 2021, the Alberta Energy Regulator (“AER”) announced a new Liability Management Framework, as part of its life-cycle management of oil and gas wells, facilities and pipelines, which imposes annual mandatory spending targets for companies for the closure of inactive wells and related infrastructure. Under the framework, the AER assigns licensees a mandatory annual spend target for their abandonment and reclamation activities, which is determined based on a licensee's proportionate share of the provincial inventory of inactive wells and related infrastructure, among other factors. Mandatory spend targets became effective January 1, 2022 and were increased for the 2023 performance year. During 2022, the government of Saskatchewan also introduced the Inactive Liability Reduction Program and the government of British Columbia updated its Dormancy and Shutdown Regulations, which provide mandatory targets for decommissioning and restoring inactive wells and facilities in those provinces. The Company has updated its forecasts of future expenditures to settle its ARO liability based on the set and forecasted annual targets. As a result, the Company’s ARO liability as at December 31, 2022 was increased on an inflated and discounted basis due to earlier forecasted expenditures to settle liabilities associated with the closure of inactive well and facilities.
GREENHOUSE GAS AND OTHER EMISSIONS
The Company has a large, diversified and balanced portfolio and a risk management strategy which incorporates an integrated GHG emissions reduction strategy and investments in technology and innovation to improve its GHG performance. The Company’s integrated GHG emissions reduction strategy includes: 1) integrating emissions reduction in project planning and operations; 2) leveraging technology to create value and enhance performance; 3) investing in research and development and supporting collaboration with industry, entrepreneurs, academia and governments; 4) focusing on continuous improvement to drive long-term emissions reduction; 5) leading in carbon capture, sequestration and storage; 6) engaging in policy and regulatory development (including trading capacity and offsetting emissions); and, 7) reviewing and developing new business opportunities and trends.
The Company is a founding member and contributor to the Pathways Alliance, an alliance of oil sands producers working collectively with federal and provincial governments, to achieve the goal of net zero GHG emissions from oil sands operations by 2050 to help Canada meet its climate goals, including its Paris Agreement commitments and 2050 net zero aspirations.
The Company, through industry associations, is working with Canadian legislators and regulators as they develop and implement new GHG emission laws and regulations to support emissions reductions and properly reflect a balanced approach to sustainable development. Internally, the Company is pursuing an integrated emissions reduction strategy and is committed to complying with existing and future emissions reduction requirements, for both GHGs and air pollutants (such as sulphur dioxide and oxides of nitrogen). The Company continues to develop strategies that will enable it to deal with the risks and opportunities associated with new GHG and air emissions policies. In addition, the Company is working with relevant parties to ensure that new policies encourage technological innovation, energy efficiency, and targeted research and development while not impacting competitiveness.
Governments in jurisdictions in which the Company operates have developed or are developing GHG regulations as part of their national and international climate change commitments. The Company uses existing GHG regulations to determine the impact of compliance costs on current and future projects. The Company monitors the development of GHG regulations on an ongoing basis in the jurisdictions in which it operates to assess the impact of future regulatory developments on the Company's operations and planned projects. In Canada, the federal government has ratified the Paris climate change agreement, with a commitment to reduce GHG emissions by 40 - 45% from 2005 levels by 2030. In 2022, the federal government released the Clean Fuel Regulations that were effective July 1, 2023, which apply to producers or importers of gasoline and diesel and require reductions in the carbon intensity associated with gasoline and diesel fuels produced and supplied in Canada. The Canadian government has also committed to cap and cut emissions from the oil and gas sector, and in December 2023, announced a regulatory framework for a national cap-and-trade system with plans to publish draft regulations by mid-2024. The draft framework currently proposed to cap 2030 emissions at 35-38% below 2018 levels (as estimated by Environment and Climate Change Canada) while providing some compliance flexibility to emit up to 20-23% below the 2019 threshold. The federal government is also developing a comprehensive management system for air pollutants and has released regulations pertaining to certain boilers, heaters and compressor engines operated by the Company.
The federal government announced its intention to increase the carbon price to $170/tonne by 2030 in annual increments of $15/tonne after 2022. 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. Such future reviews may affect the carbon price and/or the stringency of provincial systems.
In Alberta, effective January 1, 2020, the GHG regulation (the Carbon Competitiveness Incentive Regulation) was replaced with the Technology Innovation and Emissions Reduction Regulation ("TIER"). The coverage of TIER has expanded to include all of the Company's assets in Alberta (as an alternative to the federal fuel charge). In December 2022, the Alberta government published changes to TIER effective January 1, 2023 that reduce the amount of emissions allocations for facilities under the regulation. Additionally, emissions coverage within TIER was expanded to include flaring from all TIER regulated facilities. The carbon price in Alberta was $65/tonne for emissions above the TIER-regulated limits in 2023 and increases annually in $15/tonne increments to $170/tonne in 2030, which aligns with the federal carbon pricing schedule. The non-operated Scotford Upgrader and the North West Redwater bitumen upgrader and refinery are also subject to compliance under TIER.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
In British Columbia, carbon tax is currently being assessed at $65/tonne of CO 2 e on fuel consumed and gas flared and vented in the province and is expected to continue to increase by $15/tonne of CO 2 e annually until reaching $170/tonne of CO 2 e in 2030 as stated in the 2023 provincial budget, which aligns with the federal carbon pricing schedule. Additionally, the government of British Columbia announced in its 2023 provincial budget that it would replace its carbon tax for large industrial emitters with an output based pricing system that will take effect on April 1, 2024.
As part of its Prairie Resilience Plan, the Saskatchewan government has a regulation ("The Management and Reduction of Greenhouse Gases (Standards and Compliance) Regulations") that applies to facilities emitting more than 25 kilotonnes of CO 2 e annually and required the North Tangleflags in situ heavy oil facility and the Senlac in situ heavy crude oil facility to meet reduction targets for GHG emissions effective 2020. This regulation also enables facilities below the threshold to aggregate and opt into the Saskatchewan regulatory system as an alternative to the federal fuel charge. This regulation also adopts the federal carbon pricing schedule to 2030.
In Manitoba, the federal output-based pricing system and carbon pricing schedule applies for facilities with emissions greater than or equal to 10 kilotonnes of CO 2 e annually, and the federal fuel charge applies for facilities with emissions of less than 10 kilotonnes of CO 2 e annually.
By 2025, the federal government has committed to reduce methane emissions from the oil and gas sector by 40% to 45% below 2012 levels. The federal government's methane regulation came into effect on January 1, 2020 and applies nationally unless provinces reach equivalency agreements with the federal government, under which the federal regulation would not be in effect for those jurisdictions. The provinces of British Columbia, Alberta and Saskatchewan have implemented provincial methane regulations, and have reached equivalency agreements with the federal government. Accordingly, the applicable provincial methane regulations govern in the three western provinces whereas the federal methane regulation applies to methane emissions in the province of Manitoba. In 2022, the federal government announced a framework for expanding methane regulations to achieve at least a 75% reduction below 2012 levels, by 2030 with the draft regulatory framework released in November 2022 and amendments published in December 2023. Feedback on the draft regulations will continue into 2024.
In the UK, GHG regulations have been in effect since 2005. In Phase 1 (2005 - 2007) of the UK National Allocation Plan, the Company operated below its CO 2 allocation. In Phase 2 (2008 - 2012) the Company’s CO 2 allocation was decreased below the Company’s operations emissions. In Phase 3 (2013 - 2020) the Company’s CO 2 allocation was further reduced. Following the UK's withdrawal from the European Union ("EU") on January 31, 2020, a new UK Emissions Trading Scheme ("ETS") was launched on January 1, 2021. The new scheme is currently aligned with the EU ETS rules and applies to energy intensive industries, the power generation sector and aviation. The Company continues to focus on implementing CO 2 emission reduction program opportunities at its facilities and on trading mechanisms to ensure compliance with requirements now in effect.
Accounting Policies and Standards
REGULATORY DEVELOPMENTS
On May 27, 2021, the Canadian Securities Administrators ("CSA") announced the adoption of NI 52-112 and related amendments. This National Instrument replaces the previous CSA staff notice on Non-GAAP Measures. NI 52-112 governs how entities present non-GAAP and other financial measures and ratios. The requirements apply to the Company's MD&A and certain other disclosure documents beginning in 2021.
CHANGES IN ACCOUNTING POLICIES
In May 2023, the IASB issued amendments to IAS 12 "Income Taxes" related to the accounting for deferred taxes arising in those jurisdictions implementing the Organization for Economic Co-operation and Development's Pillar Two model rules ("Pillar Two Legislation"). Pillar Two Legislation did not have a significant impact on the Company’s financial results in 2023, and based on legislation substantively enacted to date in jurisdictions in which the Company currently operates, is not expected to have a significant impact on the Company's results in future periods.
In May 2021, the IASB issued amendments to IAS 12 "Income Taxes" to require companies to recognize deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements.
In February 2021, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to require companies to disclose their material accounting policy information rather than their significant accounting policies. To support this amendment the IASB also amended IFRS Practice Statement 2 "Making Materiality Judgements". The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a significant impact on the financial results of the Company. Actual results may differ from estimated amounts, and those differences may be material. A comprehensive discussion of the Company's significant accounting estimates is contained in this MD&A and the audited consolidated financial statements for the year ended December 31, 2023.
A) Depletion, Depreciation and Amortization and Impairment
Exploration and evaluation ("E&E") costs relating to activities to explore and evaluate crude oil and natural gas properties are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E assets are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. Technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. The judgements associated with the estimation of proved reserves are described below in "Crude Oil and Natural Gas Reserves".
An alternative acceptable accounting method for E&E costs under IFRS 6 "Exploration for and Evaluation of Mineral Resources" is to charge exploratory dry holes and geological and geophysical exploration costs incurred after having obtained the legal rights to explore an area against net earnings in the period incurred rather than capitalizing to E&E assets.
E&E assets are tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of related Cash Generating Units ("CGUs"), aggregated at a segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. The determination of the fair value of CGUs requires the use of assumptions and estimates including future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and production costs, discount rates, income taxes, and the potential impact of climate related matters and in accordance with related government regulations. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs.
Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. Crude oil and natural gas properties in the Exploration and Production segments are depleted using the unit-of-production method over proved reserves, except for major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future estimated development expenditures required to develop proved reserves. Estimates of proved reserves have a significant impact on net earnings, as they are a key input to the calculation of depletion expense.
The Company assesses property, plant and equipment for impairment discounted at rates currently ranging from 10% to 12% whenever events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low commodity prices for an extended period, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs a recoverability assessment related to the specific assets at the CGU level.
B) Crude Oil and Natural Gas Reserves
Reserves estimates are based on estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures, all of which are subject to many uncertainties, interpretations and judgements, including the potential impact of climate related matters and in accordance with related government regulations. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information. Reserves estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion, depreciation and amortization and for determining potential asset impairment. For example, a revision to the proved reserves estimates would result in a higher or lower depletion, depreciation and amortization charge to net earnings. Downward revisions to reserves estimates may also result in an impairment of E&E and property, plant and equipment carrying amounts.
C) Asset Retirement Obligations
The Company is required to recognize a liability for ARO associated with its property, plant and equipment, including property, plant and equipment for which underlying reserves have been de-booked, and the carrying value of the asset has been fully depleted. An ARO liability associated with the retirement of a tangible long-lived asset is recognized to the extent of a legal obligation resulting from an existing or enacted law, statute, ordinance or written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying the Company’s total ARO amount, including the potential impact of climate related matters and in accordance with related government regulations. These individual assumptions may be subject to change.

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The estimated present values of ARO related to long-term assets are recognized as a liability in the period in which they are incurred. The provision for the ARO is estimated by discounting the expected future cash flows to settle the ARO at the Company’s weighted average credit-adjusted risk-free interest rate, which is currently 5.2%. Subsequent to initial measurement, the ARO is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense whereas changes in discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and equipment. Changes in estimates would impact accretion and depletion expense. In addition, differences between actual and estimated costs to settle the ARO, timing of cash flows to settle the obligation and future inflation rates may result in gains or losses on the final settlement of the ARO.
D) Income Taxes
The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets and liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted that are expected to apply when the asset or liability is recovered. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be due.
E) Risk Management Activities
The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable quoted market inputs including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States forward interest rate yield curves, and Canadian and United States foreign exchange rates, discounted to present value as appropriate. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk. The resulting fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction and these differences may be material.
F) Purchase Price Allocations
Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties, together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation and amortization expense and impairment tests.
The Company has made various assumptions in determining the fair values of acquired assets and liabilities. The most significant assumptions and judgements relate to the estimation of the fair value of crude oil and natural gas properties. To determine the fair value of these properties, the Company estimates crude oil and natural gas reserves. Reserves estimates are based on the work performed by the Company’s internal engineers and outside consultants. The judgements associated with these estimated reserves are described above in "Crude Oil and Natural Gas Reserves". Estimates of future prices are based on prices derived from price forecasts among industry analysts and internal assessments. The Company applies estimated future prices to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimated future net revenues for the properties acquired.
G) Share-Based Compensation
The Company has made various assumptions in estimating the fair values of stock options granted including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the estimated fair value of the liability.
H) Leases
Purchase, extension and termination options are included in certain of the Company's leases to provide operational flexibility. To measure the lease liability, the Company uses judgement to assess the likelihood of exercising these options. These assessments are reviewed when significant events or circumstances indicate that the likelihood of exercising these options may have changed. The Company also uses estimates to determine its incremental borrowing costs if the interest rate implicit in the lease is not readily determinable.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
I) Government Grants
The Company receives or is eligible for government grants including emissions credits. Government grants are recognized in net earnings when there is reasonable assurance that the Company will comply with the conditions attached to the grant and the grant will be received. Emissions performance and offset credits generated under the Alberta TIER regulation are initially recorded at fair value as determined by the prescribed Alberta TIER fund compliance rates in effect at the time the credits are recognized.
Control Environment
The Company’s management, including the President, the Chief Financial Officer and the Senior Vice-President, Finance and Principal Accounting Officer, evaluated the effectiveness of disclosure controls and procedures as at December 31, 2023, and concluded that disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings and other reports filed with securities regulatory authorities in Canada and the United States is recorded, processed, summarized and reported within the time periods specified and such information is accumulated and communicated to the Company’s management to allow timely decisions regarding required disclosures.
The Company’s management, including the President, the Chief Financial Officer, and the Senior Vice-President, Finance and Principal Accounting Officer, also evaluated the effectiveness of internal control over financial reporting as at December 31, 2023, and concluded that internal control over financial reporting is effective. Further, there were no changes in the Company’s internal control over financial reporting during 2023 that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.
While the Company’s management believes that the Company’s disclosure controls and procedures and internal control over financial reporting provide a reasonable level of assurance they are effective, they recognize that all control systems have inherent limitations. Because of its inherent limitations, the Company’s control systems may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
Non-GAAP and Other Financial Measures
This MD&A includes references to non-GAAP and other financial measures as defined in NI 52-112. These financial measures are used by the Company to evaluate its financial performance, financial position and cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS 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 audited consolidated financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company’s non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below.
ADJUSTED NET EARNINGS FROM OPERATIONS
Adjusted net earnings from operations is a non-GAAP financial measure that adjusts net earnings as presented in the Company's consolidated Statements of Earnings, for non-operating items, net of tax impacts. The Company considers adjusted net earnings from operations a key measure in evaluating its performance, as it demonstrates the Company’s ability to generate after-tax operating earnings from its core business areas. A reconciliation for adjusted net earnings from operations is presented below.

($ millions) |  | 2023 |  | 2022 |  | 2021
Net earnings |  | $ | 8,233 |  |  | $ | 10,937 |  |  | $ | 7,664 |
Share-based compensation, net of tax (1) |  | 474 |  |  | 780 |  |  | 495 |
Unrealized risk management loss (gain), net of tax (2) |  | 7 |  |  | (25) |  |  | 16 |
Unrealized foreign exchange (gain) loss, net of tax (3) |  | (260) |  |  | 852 |  |  | (205) |
Realized foreign exchange (gain) loss, net of tax (4) |  | — |  |  | (62) |  |  | 118 |
Gain on acquisitions, net of tax (5) |  | — |  |  | — |  |  | (478) |
Gain from investments, net of tax (6) |  | (34) |  |  | (182) |  |  | (132) |
Recoverability charge, net of tax (7) (8) |  | 113 |  |  | 651 |  |  | — |
Other, net of tax (9) |  | — |  |  | (88) |  |  | (58) |
Non-operating items, net of tax |  | 300 |  |  | 1,926 |  |  | (244) |
Adjusted net earnings from operations |  | $ | 8,533 |  |  | $ | 12,863 |  |  | $ | 7,420 |

(1)Share-based compensation includes costs incurred under the Company's Stock Option Plan and PSU plan. The fair value of the share-based compensation is recognized as a liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings. Pre-tax share-based compensation for 2023 was an expense of $491 million (2022 – $804 million expense; 2021 – $514 million expense).
(2)Derivative financial instruments are recognized at fair value on the Company’s balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than those amounts reflected in the Company's audited consolidated financial statements due to changes in prices of the underlying items hedged, primarily crude oil, natural gas and foreign exchange. Pre-tax unrealized risk management loss for 2023 was $12 million (2022 – $28 million gain; 2021 – $19 million loss).
(3)Unrealized foreign exchange losses and gains result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps in 2022, and are recognized in net earnings. Pre- and after-tax amounts for these unrealized foreign exchange losses and gains are the same.
(4)During 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023, resulting in a realized foreign exchange loss of $7 million. Also, during 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the US$1,100 million 6.25% US dollar debt securities due March 2038, resulting in a realized foreign exchange gain of $69 million. During 2021, the Company repaid US$500 million of 3.45% debt securities, resulting in a realized foreign exchange loss of $118 million. Pre- and after-tax amounts for these realized foreign exchange gains and losses are the same.
(5)During 2021, the Company completed two acquisitions resulting in a pre- and after-tax gain of $478 million.
(6)The Company’s investments have been accounted for at fair value through profit and loss and are measured each period with (gains) losses recognized in net earnings. There is zero net tax impact on these (gains) losses from investments.
(7)The Company recognized a pre-tax recoverability charge of $436 million in depletion, depreciation and amortization expense related to revised project scope and the current cost environment for planned decommissioning and abandonment activities at the Ninian field in the North Sea in 2023. The costs are considered to be capital in nature, consistent with the treatment of all abandonment related expenditures for the purpose of the Company's non-GAAP measures.
(8)The Company recognized a pre-tax recoverability charge of $1,620 million in depletion, depreciation and amortization expense at December 31, 2022 relating to the de-booking of reserves at the Ninian field in the North Sea. Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked associated crude oil reserves as at December 31, 2022, and is accelerating abandonment.
(9)During 2022, the Company recognized the impact of government grant income under the provincial well-site rehabilitation programs of $114 million (2021 – $75 million).

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P r i n c i p a l D o c u m e n t s E x h i b i t s
ADJUSTED FUNDS FLOW
Adjusted funds flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures excluding the impact of government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets. The Company considers adjusted funds flow a key measure in evaluating its performance, as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. A reconciliation for adjusted funds flow, from cash flows from operating activities is presented below.

($ millions) |  | 2023 |  | 2022 |  | 2021
Cash flows from operating activities |  | $ | 12,353 |  |  | $ | 19,391 |  |  | $ | 14,478 |
Net change in non-cash working capital |  | 2,417 |  |  | (79) |  |  | (964) |
Abandonment expenditures, net (1) |  | 509 |  |  | 335 |  |  | 232 |
Movements in other long-term assets (2) |  | (5) |  |  | 144 |  |  | (13) |
Adjusted funds flow |  | $ | 15,274 |  |  | $ | 19,791 |  |  | $ | 13,733 |

(1)Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the “Abandonment Expenditures, net” section below.
(2)Includes the unamortized cost of the share bonus program, accrued interest on the deferred PRT recovery, accrued interest on subordinated debt advances to NWRP and prepaid cost of service tolls.
ADJUSTED NET EARNINGS FROM OPERATIONS AND ADJUSTED FUNDS FLOW, PER SHARE (BASIC AND DILUTED)
Adjusted net earnings from operations and adjusted funds flow, per common share (basic and diluted), are non-GAAP ratios that represent those non-GAAP measures divided by the weighted average number of basic and diluted common shares outstanding for the period, respectively, as presented in note 17 to the Company's audited consolidated financial statements. These non-GAAP measures, disclosed on a per share basis, enable a comparison to the per share amounts disclosed in the Company's financial statements prepared in accordance with IFRS.
ABANDONMENT EXPENDITURES, NET
Abandonment expenditures, net, is a non-GAAP financial measure that represents the abandonment expenditures to settle asset retirement obligations as reflected in the Company's historical annual capital budgets. Abandonment expenditures, net is calculated as abandonment expenditures, as presented in the Company's audited consolidated Statements of Cash Flows, adjusted for the impact of government grant income under the provincial well-site rehabilitation programs. A reconciliation of abandonment expenditures, net is presented below.

($ millions) |  | 2023 |  | 2022 |  | 2021
Abandonment expenditures |  | $ | 509 |  |  | $ | 449 |  |  | $ | 307 |
Government grants for abandonment expenditures |  | — |  |  | (114) |  |  | (75) |
Abandonment expenditures, net |  | $ | 509 |  |  | $ | 335 |  |  | $ | 232 |

NETBACK
Netback is a non-GAAP ratio that represents net cash flows provided from core activities after the impact of all costs associated with bringing a product to market, on a per unit basis. The Company considers netback a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. Refer to the "Operating Highlights – Exploration and Production", "Per Unit Results – Exploration and Production", and "Per Unit Results – Oil Sands Mining and Upgrading" sections of this MD&A for the netback calculations on a per unit basis for crude oil and NGLs, natural gas and on a total barrels of oil equivalent basis.
The netback calculations include the non-GAAP financial measures: realized price and transportation, reconciled below to their respective line item in note 22 to the Company's audited consolidated financial statements.

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P r i n c i p a l D o c u m e n t s E x h i b i t s
REALIZED PRICE ($/BBL AND $/BOE) – EXPLORATION AND PRODUCTION
Realized price ($/bbl and $/BOE) is a non-GAAP ratio calculated as realized crude oil and NGLs sales and total realized BOE sales (non-GAAP financial measures) divided by respective sales volumes. Realized crude oil and NGLs sales and total realized BOE sales include the impact of blending and feedstock costs and other by-product sales. The Company considers realized price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit the Company obtained on the market for its crude oil and NGLs sales volumes and BOE sales volumes.
Reconciliations for Exploration and Production realized crude oil and NGLs sales and BOE sales and the calculations for realized price are presented below.

($ millions, except bbl/d and $/bbl) |  |  |  |  |  |  |  |  | 2023 |  | 2022 |  | 2021
Crude oil and NGLs (bbl/d) |  |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  |  |  |  |  |  |  | 497,604 |  |  | 480,691 |  |  | 471,331 |
International |  |  |  |  |  |  |  |  |  |  |  |  |
North Sea |  |  |  |  |  |  |  |  | 10,749 |  |  | 13,215 |  |  | 18,942 |
Offshore Africa |  |  |  |  |  |  |  |  | 14,882 |  |  | 14,866 |  |  | 13,452 |
Total International |  |  |  |  |  |  |  |  | 25,631 |  |  | 28,081 |  |  | 32,394 |
Total sales volumes |  |  |  |  |  |  |  |  | 523,235 |  |  | 508,772 |  |  | 503,725 |
Crude oil and NGLs sales (1) (2) |  |  |  |  |  |  |  |  | $ | 18,387 |  |  | $ | 22,072 |  |  | $ | 15,505 |
Less: Blending and feedstock costs (3) |  |  |  |  |  |  |  |  | 4,568 |  |  | 5,239 |  |  | 3,792 |
Realized crude oil and NGLs sales |  |  |  |  |  |  |  |  | $ | 13,819 |  |  | $ | 16,833 |  |  | $ | 11,713 |
Realized price ($/bbl) |  |  |  |  |  |  |  |  | $ | 72.36 |  |  | $ | 90.64 |  |  | $ | 63.71 |

(1)Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2)Includes other miscellaneous income in the segment.
(3)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section.

($ millions, except BOE/d and $/BOE) |  |  |  |  |  |  |  |  | 2023 |  | 2022 |  | 2021
Barrels of oil equivalent (BOE/d) |  |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  |  |  |  |  |  |  | 854,138 |  |  | 826,526 |  |  | 751,330 |
International |  |  |  |  |  |  |  |  |  |  |  |  |
North Sea |  |  |  |  |  |  |  |  | 11,034 |  |  | 13,598 |  |  | 19,512 |
Offshore Africa |  |  |  |  |  |  |  |  | 16,638 |  |  | 16,933 |  |  | 15,385 |
Total International |  |  |  |  |  |  |  |  | 27,672 |  |  | 30,531 |  |  | 34,897 |
Total sales volumes |  |  |  |  |  |  |  |  | 881,810 |  |  | 857,057 |  |  | 786,227 |
Barrels of oil equivalent sales (1) (2) |  |  |  |  |  |  |  |  | $ | 20,820 |  |  | $ | 27,071 |  |  | $ | 18,025 |
Less: Blending and feedstock costs (3) |  |  |  |  |  |  |  |  | 4,568 |  |  | 5,239 |  |  | 3,792 |
Less: Sulphur income |  |  |  |  |  |  |  |  | (14) |  |  | (88) |  |  | (21) |
Realized barrels of oil equivalent sales |  |  |  |  |  |  |  |  | $ | 16,266 |  |  | $ | 21,920 |  |  | $ | 14,254 |
Realized price ($/BOE) |  |  |  |  |  |  |  |  | $ | 50.54 |  |  | $ | 70.07 |  |  | $ | 49.67 |

(1)Barrels of oil equivalent sales includes crude oil and NGLs sales and natural gas sales in note 22 to the Company's audited consolidated financial statements.
(2)Includes other miscellaneous income in the segment.
(3)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section.

Canadian Natural 2023 Annual Report | 40

P r i n c i p a l D o c u m e n t s E x h i b i t s
TRANSPORTATION – EXPLORATION AND PRODUCTION
Transportation ($/BOE, $/bbl and $/Mcf) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by the respective sales volumes. The Company calculates transportation to demonstrate its cost to deliver products to the market excluding the impact of blending and feedstock costs. A reconciliation for Exploration and Production transportation and the calculations for transportation on a per unit basis are presented below.

($ millions, except $ per unit amounts) |  |  |  |  |  |  |  |  | 2023 |  | 2022 |  | 2021
Transportation, blending and feedstock (1) |  |  |  |  |  |  |  |  | $ | 5,816 |  |  | $ | 6,401 |  |  | $ | 4,780 |
Less: Blending and feedstock costs |  |  |  |  |  |  |  |  | 4,568 |  |  | 5,239 |  |  | 3,792 |
Transportation |  |  |  |  |  |  |  |  | $ | 1,248 |  |  | $ | 1,162 |  |  | $ | 988 |
Transportation ($/BOE) |  |  |  |  |  |  |  |  | $ | 3.88 |  |  | $ | 3.72 |  |  | $ | 3.44 |
Amounts attributed to crude oil and NGLs |  |  |  |  |  |  |  |  | $ | 807 |  |  | $ | 767 |  |  | $ | 710 |
Transportation ($/bbl) |  |  |  |  |  |  |  |  | $ | 4.23 |  |  | $ | 4.13 |  |  | $ | 3.86 |
Amounts attributed to natural gas |  |  |  |  |  |  |  |  | $ | 441 |  |  | $ | 395 |  |  | $ | 278 |
Transportation ($/Mcf) |  |  |  |  |  |  |  |  | $ | 0.56 |  |  | $ | 0.51 |  |  | $ | 0.45 |

(1)Transportation, blending and feedstock in note 22 to the Company's audited consolidated financial statements.
NORTH AMERICA – REALIZED PRODUCT PRICES AND ROYALTIES
Realized crude oil and NGLs price ($/bbl) is a non-GAAP ratio calculated as realized crude oil and NGLs sales (non-GAAP financial measure) divided by sales volumes. Realized crude oil and NGLs sales include the impact of blending and feedstock costs. The Company considers the realized crude oil and NGLs price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its crude oil and NGLs sales volumes.
Crude oil and NGLs royalty rate is a non-GAAP ratio that is calculated as crude oil and NGLs royalties divided by realized crude oil and NGLs sales. The Company considers crude oil and NGLs royalty rate a key measure in evaluating its performance, as it describes the Company’s royalties for crude oil and NGLs sales volumes on a per unit basis.
A reconciliation for North America realized crude oil and NGLs sales and the calculations for realized crude oil and NGLs prices and the royalty rates are presented below.

($ millions, except $/bbl and royalty rates) |  | 2023 |  | 2022 |  | 2021
Crude oil and NGLs sales (1) |  | $ | 17,375 |  |  | $ | 20,755 |  |  | $ | 14,478 |
Less: Blending and feedstock costs (2) |  | 4,568 |  |  | 5,239 |  |  | 3,792 |
Realized crude oil and NGLs sales |  | $ | 12,807 |  |  | $ | 15,516 |  |  | $ | 10,686 |
Realized crude oil and NGLs prices ($/bbl) |  | $ | 70.51 |  |  | $ | 88.43 |  |  | $ | 62.10 |
Crude oil and NGLs royalties (3) |  | $ | 2,340 |  |  | $ | 3,445 |  |  | $ | 1,558 |
Crude oil and NGLs royalty rates |  | 18% |  | 22% |  | 15%

(1)Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled above in the "Transportation – Exploration and Production" section.
(3)Item is a component of royalties in note 22 to the Company's audited consolidated financial statements.

41 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
REALIZED PRODUCT PRICES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING
Realized SCO sales price ($/bbl) is a non-GAAP ratio calculated as realized SCO sales (non-GAAP financial measure) including the impact of blending and feedstock costs, divided by SCO sales volumes. The Company considers realized SCO sales price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its SCO sales volumes.
Transportation ($/bbl) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by SCO sales volumes. The Company calculates transportation to demonstrate its cost to deliver product to the market excluding the impact of blending and feedstock costs.
Reconciliations for Oil Sands Mining and Upgrading realized SCO sales and transportation and the calculations for realized SCO sales price and transportation on a per unit basis are presented below.

($ millions, except for bbl/d and $/bbl) |  |  |  |  |  |  |  |  | 2023 |  | 2022 |  | 2021
SCO sales volumes (bbl/d) |  |  |  |  |  |  |  |  | 449,282 |  |  | 428,820 |  |  | 447,230 |
Crude oil and NGLs sales (1) (2) |  |  |  |  |  |  |  |  | $ | 18,661 |  |  | $ | 20,804 |  |  | $ | 14,033 |
Less: Blending and feedstock costs |  |  |  |  |  |  |  |  | 2,253 |  |  | 2,384 |  |  | 1,309 |
Realized SCO sales |  |  |  |  |  |  |  |  | $ | 16,408 |  |  | $ | 18,420 |  |  | $ | 12,724 |
Realized SCO sales price ($/bbl) |  |  |  |  |  |  |  |  | $ | 100.06 |  |  | $ | 117.69 |  |  | $ | 77.95 |
Transportation, blending and feedstock (3) |  |  |  |  |  |  |  |  | $ | 2,563 |  |  | $ | 2,652 |  |  | $ | 1,505 |
Less: Blending and feedstock costs |  |  |  |  |  |  |  |  | 2,253 |  |  | 2,384 |  |  | 1,309 |
Transportation |  |  |  |  |  |  |  |  | $ | 310 |  |  | $ | 268 |  |  | $ | 196 |
Transportation ($/bbl) |  |  |  |  |  |  |  |  | $ | 1.89 |  |  | $ | 1.71 |  |  | $ | 1.21 |

(1)Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2)Excludes other miscellaneous income not pertaining to crude oil and NGLs sales.
(3)Transportation, blending and feedstock in note 22 to the Company's audited consolidated financial statements.
CHANGE IN COMPOSITION OF NON-GAAP FINANCIAL MEASURE
During the fourth quarter of 2023, the Company revised the composition of its Net Capital Expenditures non-GAAP financial measure to exclude expenditures related to the Company's abandonment program. The revision was made during Management's assessment of its annual capital budgeting process, and will provide users a better representation of the composition of the Company's capital budget, and in evaluating performance. The composition of this measure has been updated for all periods presented.
NET CAPITAL EXPENDITURES
Net capital expenditures is a non-GAAP financial measure that represents cash flows used in investing activities as presented in the Company's audited consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, proceeds from investments, the repayment of NWRP subordinated debt advances, the settlement of long-term debt assumed in acquisitions, and cash flows from investing activities not included in the Company's capital budget. The Company includes acquisition and disposition capital in net capital expenditures. The Company considers net capital expenditures a key measure in evaluating its performance, as it provides an understanding of the Company’s capital spending activities in comparison to the Company’s annual capital budget. A reconciliation of net capital expenditures is presented below.

($ millions) |  | 2023 |  | 2022 |  | 2021
Cash flows used in investing activities |  | $ | 4,858 |  |  | $ | 4,987 |  |  | $ | 3,703 |
Net change in non-cash working capital |  | 51 |  |  | 149 |  |  | 107 |
Proceeds from investment |  | — |  |  | — |  |  | 128 |
Repayment of NWRP subordinated debt advances |  | — |  |  | — |  |  | 555 |
Settlement of long-term debt acquired (1) |  | — |  |  | — |  |  | 183 |
Net capital expenditures (2) |  | 4,909 |  |  | 5,136 |  |  | 4,676 |
Abandonment expenditures, net (3) |  | 509 |  |  | 335 |  |  | 232 |
Capital and abandonment expenditures |  | $ | 5,418 |  |  | $ | 5,471 |  |  | $ | 4,908 |

(1)Relates to the settlement of long-term debt assumed in the acquisition of Storm in 2021.
(2)For 2023, includes base capital expenditures of $3,958 million and strategic growth capital expenditures of $925 million. Strategic growth capital expenditures represent the allocation of the Company's free cash flow that will be directed to strategic capital growth opportunities that target to increase production volumes in future periods and that exceed the Company's base capital expenditures for the current fiscal year, as outlined in the Company's capital budget.
(3)Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the “Abandonment Expenditures, net” section above.

Canadian Natural 2023 Annual Report | 42

P r i n c i p a l D o c u m e n t s E x h i b i t s
LIQUIDITY
Liquidity is a non-GAAP financial measure that represents the availability of readily available undrawn bank credit facilities, cash and cash equivalents, and other highly liquid assets to meet short-term funding requirements and to assist in assessing the Company's financial position. The Company’s calculation of liquidity is presented below.

($ millions) |  | 2023 |  | 2022 |  | 2021
Undrawn bank credit facilities |  | $ | 5,450 |  |  | $ | 5,520 |  |  | $ | 6,098 |
Cash and cash equivalents |  | 877 |  |  | 920 |  |  | 744 |
Investments |  | 525 |  |  | 491 |  |  | 309 |
Liquidity |  | $ | 6,852 |  |  | $ | 6,931 |  |  | $ | 7,151 |

LONG-TERM DEBT, NET
Long-term debt, net, is a capital management measure that represents long-term debt less cash and cash equivalents, as disclosed in note 16 to the Company's audited consolidated financial statements. A reconciliation of the Company's long-term debt, net is presented below.

($ millions) |  | 2023 |  | 2022 |  | 2021
Long-term debt |  | $ | 10,799 |  |  | $ | 11,445 |  |  | $ | 14,694 |
Less: cash and cash equivalents |  | 877 |  |  | 920 |  |  | 744 |
Long-term debt, net |  | $ | 9,922 |  |  | $ | 10,525 |  |  | $ | 13,950 |

DEBT TO BOOK CAPITALIZATION
Debt to book capitalization is a capital management measure intended to enable financial statement users to evaluate the Company's capital structure, as disclosed in note 16 to the Company's audited consolidated financial statements.
AFTER-TAX RETURN ON AVERAGE CAPITAL EMPLOYED
After-tax return on average capital employed as defined by the Company is a non-GAAP ratio. The ratio is calculated as net earnings plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of average capital employed (defined as current and long-term debt plus shareholders' equity) for the twelve month trailing period. The Company considers this ratio a key measure in evaluating the Company’s ability to generate profit and the efficiency with which it employs capital. A reconciliation of the Company's after-tax return on average capital employed is presented below.

($ millions, except ratios) | 2023 |  | 2022 |  | 2021
Interest adjusted after-tax return: |  |  |  |  |
Net earnings (loss), 12 months trailing | $ | 8,233 |  |  | $ | 10,937 |  |  | $ | 7,664 |
Interest and other financing expense, net of tax, 12 months trailing (1) | 490 |  |  | 424 |  |  | 547 |
Interest adjusted after-tax return | $ | 8,723 |  |  | $ | 11,361 |  |  | $ | 8,211 |
12 months average current portion long-term debt (2) | $ | 1,259 |  |  | $ | 1,359 |  |  | $ | 1,483 |
12 months average long-term debt (2) | 10,354 |  |  | 11,761 |  |  | 16,769 |
12 months average common shareholders' equity (2) | 38,974 |  |  | 38,218 |  |  | 34,458 |
12 months average capital employed | $ | 50,587 |  |  | $ | 51,338 |  |  | $ | 52,710 |
After-tax return on average capital employed | 17% |  | 22% |  | 16%

(1)The blended tax rate on interest was 23% for December 31, 2023, 23% for December 31, 2022, and 23% for December 31, 2021.
(2)For the purpose of this non-GAAP ratio, the measurement of average current and long-term debt and common shareholders' equity are determined on a consistent basis, as an average of the opening and quarterly period end values for the 12 month trailing period for each of the periods presented.

43 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
Outlook
The Company continues to implement its strategy of maintaining a large portfolio of varied projects, which the Company believes will enable it, over an extended period of time, to provide consistent growth in production and create shareholder value. Annual budgets are developed, scrutinized throughout the year and revised if necessary in the context of targeted financial ratios, project returns, product pricing expectations, and balance in project risk and time horizons. The Company maintains a high ownership level and operatorship level in all of its properties and can therefore control the nature, timing and extent of capital expenditures in each of its project areas.
2024 CAPITAL BUDGET
On December 14, 2023, the Company announced its 2024 capital budget targeted at approximately $5,420 million, and targets to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024. Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns and the balancing of project risks and time horizons. The 2024 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
Other
SENSITIVITY ANALYSIS
The following table is indicative of the annualized sensitivities of cash flows from operating activities and net earnings due to changes in certain key variables. The analysis is based on business conditions and sales volumes during the fourth quarter of 2023, excluding mark-to-market gains (losses) on risk management activities and is not necessarily indicative of future results. Each separate line item in the sensitivity analysis shows the effect of a change in that variable only with all other variables being held constant.

| Cash flows from Operating Activities ($ millions) |  | Cash flows from Operating Activities (per common share, basic) |  | Net earnings ($ millions) |  | Net earnings (per common share, basic)
Price changes |  |  |  |  |  |  |
Crude oil – WTI US$1.00/bbl |  |  |  |  |  |  |
Excluding financial derivatives | $ | 334 |  |  | $ | 0.31 |  |  | $ | 334 |  |  | $ | 0.31 |
Natural gas – AECO C$0.10/Mcf (1) |  |  |  |  |  |  |
Excluding financial derivatives | $ | 42 |  |  | $ | 0.04 |  |  | $ | 42 |  |  | $ | 0.04 |
Including financial derivatives | $ | 40 |  |  | $ | 0.04 |  |  | $ | 40 |  |  | $ | 0.04 |
Volume changes |  |  |  |  |  |  |
Crude oil – 10,000 bbl/d | $ | 174 |  |  | $ | 0.16 |  |  | $ | 149 |  |  | $ | 0.14 |
Natural gas – 10 MMcf/d | $ | 3 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Foreign currency rate change |  |  |  |  |  |  |
$0.01 change in US$ (1) |  |  |  |  |  |  |
Including financial derivatives | $ | 270 |  |  | $ | 0.25 |  |  | $ | 150 |  |  | $ | 0.14 |
Interest rate change – 1% | $ | 5 |  |  | $ | — |  |  | $ | 5 |  |  | $ | — |

(1)For details of financial instruments in place, refer to note 19 to the Company’s audited consolidated financial statements as at December 31, 2023.

Canadian Natural 2023 Annual Report | 44

P r i n c i p a l D o c u m e n t s E x h i b i t s
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES

| Q1 | Q2 | Q3 | Q4 | 2023 | 2022 | 2021
Crude oil and NGLs (bbl/d) |  |  |  |  |  |  |
North America – Exploration and Production | 477,349 |  | 465,143 |  | 519,581 |  | 521,579 |  | 496,100 |  | 479,971 |  | 472,621 |
North America – Oil Sands Mining and Upgrading (1) | 458,228 |  | 355,246 |  | 490,853 |  | 500,133 |  | 451,339 |  | 425,945 |  | 448,133 |
International |  |  |  |  |  |  |
North Sea | 13,240 |  | 12,699 |  | 12,016 |  | 12,616 |  | 12,639 |  | 12,890 |  | 17,633 |
Offshore Africa | 14,091 |  | 13,821 |  | 12,703 |  | 13,213 |  | 13,452 |  | 14,343 |  | 14,017 |
Total International | 27,331 |  | 26,520 |  | 24,719 |  | 25,829 |  | 26,091 |  | 27,233 |  | 31,650 |
Total Crude oil and NGLs | 962,908 |  | 846,909 |  | 1,035,153 |  | 1,047,541 |  | 973,530 |  | 933,149 |  | 952,404 |
Natural gas (MMcf/d) (2) |  |  |  |  |  |  |
North America | 2,127 |  | 2,072 |  | 2,139 |  | 2,218 |  | 2,139 |  | 2,075 |  | 1,680 |
International |  |  |  |  |  |  |
North Sea | 3 |  | 2 |  | 1 |  | 2 |  | 2 |  | 2 |  | 3 |
Offshore Africa | 9 |  | 11 |  | 11 |  | 11 |  | 10 |  | 13 |  | 12 |
Total International | 12 |  | 13 |  | 12 |  | 13 |  | 12 |  | 15 |  | 15 |
Total Natural gas | 2,139 |  | 2,085 |  | 2,151 |  | 2,231 |  | 2,151 |  | 2,090 |  | 1,695 |
Barrels of oil equivalent (BOE/d) |  |  |  |  |  |  |
North America – Exploration and Production | 831,846 |  | 810,451 |  | 876,099 |  | 891,225 |  | 852,633 |  | 825,806 |  | 752,620 |
North America – Oil Sands Mining and Upgrading (1) | 458,228 |  | 355,246 |  | 490,853 |  | 500,133 |  | 451,339 |  | 425,945 |  | 448,133 |
International |  |  |  |  |  |  |
North Sea | 13,659 |  | 12,976 |  | 12,199 |  | 12,880 |  | 12,925 |  | 13,273 |  | 18,203 |
Offshore Africa | 15,658 |  | 15,653 |  | 14,463 |  | 15,075 |  | 15,208 |  | 16,410 |  | 15,950 |
Total International | 29,317 |  | 28,629 |  | 26,662 |  | 27,955 |  | 28,133 |  | 29,683 |  | 34,153 |
Total Barrels of oil equivalent | 1,319,391 |  | 1,194,326 |  | 1,393,614 |  | 1,419,313 |  | 1,332,105 |  | 1,281,434 |  | 1,234,906 |

(1)SCO production before royalties excludes SCO consumed internally as diesel.
(2)Natural gas production volumes approximate sales volumes.

45 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
PER UNIT RESULTS – EXPLORATION AND PRODUCTION

| Q1 | Q2 | Q3 | Q4 | 2023 | 2022 | 2021
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |  |
Realized price (2) | $ | 58.85 |  | $ | 72.06 |  | $ | 87.83 |  | $ | 69.39 |  | $ | 72.36 |  | $ | 90.64 |  | $ | 63.71 |
Transportation (2) | 4.52 |  | 4.57 |  | 4.07 |  | 3.83 |  | 4.23 |  | 4.13 |  | 3.86 |
Realized price, net of transportation (2) | 54.33 |  | 67.49 |  | 83.76 |  | 65.56 |  | 68.13 |  | 86.51 |  | 59.85 |
Royalties (3) | 10.09 |  | 11.09 |  | 17.32 |  | 11.38 |  | 12.55 |  | 18.91 |  | 8.59 |
Production expense (4) | 16.93 |  | 18.38 |  | 14.40 |  | 15.05 |  | 16.12 |  | 18.17 |  | 14.71 |
Netback (2) | $ | 27.31 |  | $ | 38.02 |  | $ | 52.04 |  | $ | 39.13 |  | $ | 39.46 |  | $ | 49.43 |  | $ | 36.55 |
Natural gas ($/Mcf) (1) |  |  |  |  |  |  |
Realized price (5) | $ | 4.27 |  | $ | 2.53 |  | $ | 2.81 |  | $ | 2.80 |  | $ | 3.10 |  | $ | 6.55 |  | $ | 4.07 |
Transportation (6) | 0.55 |  | 0.58 |  | 0.56 |  | 0.54 |  | 0.56 |  | 0.51 |  | 0.45 |
Realized price, net of transportation | 3.72 |  | 1.95 |  | 2.25 |  | 2.26 |  | 2.54 |  | 6.04 |  | 3.62 |
Royalties (3) | 0.28 |  | 0.07 |  | 0.09 |  | 0.09 |  | 0.13 |  | 0.61 |  | 0.22 |
Production expense (4) | 1.47 |  | 1.37 |  | 1.25 |  | 1.13 |  | 1.30 |  | 1.22 |  | 1.18 |
Netback | $ | 1.97 |  | $ | 0.51 |  | $ | 0.91 |  | $ | 1.04 |  | $ | 1.11 |  | $ | 4.21 |  | $ | 2.22 |
Barrels of oil equivalent ($/BOE) (1) |  |  |  |  |  |  |
Realized price (2) | $ | 44.98 |  | $ | 48.94 |  | $ | 59.40 |  | $ | 48.41 |  | $ | 50.54 |  | $ | 70.07 |  | $ | 49.67 |
Transportation (2) | 4.03 |  | 4.11 |  | 3.78 |  | 3.61 |  | 3.88 |  | 3.72 |  | 3.44 |
Realized price, net of transportation (2) | 40.95 |  | 44.83 |  | 55.62 |  | 44.80 |  | 46.66 |  | 66.35 |  | 46.23 |
Royalties (3) | 6.56 |  | 6.75 |  | 10.61 |  | 7.05 |  | 7.77 |  | 12.75 |  | 5.98 |
Production expense (4) | 13.51 |  | 14.24 |  | 11.64 |  | 11.75 |  | 12.74 |  | 13.76 |  | 11.98 |
Netback (2) | $ | 20.88 |  | $ | 23.84 |  | $ | 33.37 |  | $ | 26.00 |  | $ | 26.15 |  | $ | 39.84 |  | $ | 28.27 |

(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as royalties divided by respective sales volumes.
(4)Calculated as production expense divided by respective sales volumes.
(5)Calculated as natural gas sales divided by natural gas sales volumes.
(6)Calculated as natural gas transportation expense divided by natural gas sales volumes.
PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING

| Q1 | Q2 | Q3 | Q4 | 2023 | 2022 | 2021
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |  |
Realized SCO sales price (2) | $ | 96.07 |  | $ | 95.08 |  | $ | 108.55 |  | $ | 98.73 |  | $ | 100.06 |  | $ | 117.69 |  | $ | 77.95 |
Bitumen royalties (3) | 10.04 |  | 13.58 |  | 21.90 |  | 11.57 |  | 14.43 |  | 20.71 |  | 6.62 |
Transportation (2) | 1.52 |  | 2.03 |  | 2.18 |  | 1.85 |  | 1.89 |  | 1.71 |  | 1.21 |
Production expense (4) | 25.06 |  | 31.28 |  | 22.12 |  | 20.96 |  | 24.32 |  | 26.04 |  | 20.91 |
Netback (2) | $ | 59.45 |  | $ | 48.19 |  | $ | 62.35 |  | $ | 64.35 |  | $ | 59.42 |  | $ | 69.23 |  | $ | 49.21 |

(1)For SCO sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as royalties divided by sales volumes.
(4)Calculated as production costs divided by sales volumes.

Canadian Natural 2023 Annual Report | 46

P r i n c i p a l D o c u m e n t s E x h i b i t s
TRADING AND SHARE STATISTICS

| Q1 | Q2 | Q3 | Q4 | 2023 | 2022
TSX – C$ |  |  |  |  |  |
Trading volume (thousands) | 384,779 |  | 373,032 |  | 475,363 |  | 463,881 |  | 1,697,055 |  | 1,533,722 |
Share Price ($/share) |  |  |  |  |  |
High | $ | 82.89 |  | $ | 83.18 |  | $ | 90.70 |  | $ | 93.44 |  | $ | 93.44 |  | $ | 88.18 |
Low | $ | 67.13 |  | $ | 69.83 |  | $ | 71.61 |  | $ | 81.68 |  | $ | 67.13 |  | $ | 54.20 |
Close | $ | 74.79 |  | $ | 74.48 |  | $ | 87.84 |  | $ | 86.81 |  | $ | 86.81 |  | $ | 75.19 |
Market capitalization as at December 31 ($ millions) |  |  |  |  | $ | 93,096 |  | $ | 82,907 |
Shares outstanding (thousands) |  |  |  |  | 1,072,408 |  | 1,102,636 |
NYSE – US$ |  |  |  |  |  |
Trading volume (thousands) | 137,402 |  | 126,047 |  | 132,453 |  | 206,964 |  | 602,866 |  | 755,722 |
Share Price ($/share) |  |  |  |  |  |
High | $ | 62.29 |  | $ | 62.33 |  | $ | 67.23 |  | $ | 68.74 |  | $ | 68.74 |  | $ | 70.60 |
Low | $ | 48.81 |  | $ | 52.66 |  | $ | 53.62 |  | $ | 59.39 |  | $ | 48.81 |  | $ | 42.32 |
Close | $ | 55.35 |  | $ | 56.26 |  | $ | 64.67 |  | $ | 65.52 |  | $ | 65.52 |  | $ | 55.53 |
Market capitalization as at December 31 ($ millions) |  |  |  |  | $ | 70,264 |  | $ | 61,229 |
Shares outstanding (thousands) |  |  |  |  | 1,072,408 |  | 1,102,636 |

47 | Canadian Natural 2023 Annual Report

P r i n c i p a l D o c u m e n t s E x h i b i t s
Additional Disclosure
CERTIFICATIONS
The required disclosure is included in Exhibits 31.1, 31.2, 32.1, 32.2 and 97 to this Annual Report on Form 40-F.
DISCLOSURE CONTROLS AND PROCEDURES
As of the end of the registrant’s fiscal year ended December 31, 2023, an evaluation of the effectiveness of Canadian Natural’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), was carried out by Canadian Natural’s management with the participation of Canadian Natural’s principal executive officer and principal financial officer. Based upon the evaluation, Canadian Natural’s principal executive officer and principal financial officer have concluded that as of the end of the fiscal year, Canadian Natural’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to Canadian Natural’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
It should be noted that while Canadian Natural’s principal executive officer and principal financial officer believe that Canadian Natural’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect Canadian Natural’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The required disclosure is included in the “Management’s Assessment of Internal Control Over Financial Reporting” that accompanies Canadian Natural’s audited consolidated financial statements for the fiscal year ended December 31, 2023, filed as part of this Annual Report on Form 40-F.
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
The required disclosure is included in the “Report of Independent Registered Public Accounting Firm” that accompanies Canadian Natural’s audited consolidated financial statements for the fiscal year ended December 31, 2023, filed as part of this Annual Report on Form 40-F.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
During the fiscal year ended December 31, 2023, there were no changes in Canadian Natural’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, Canadian Natural’s internal control over financial reporting.
NOTICES PURSUANT TO REGULATION BTR
None.
AUDIT COMMITTEE FINANCIAL EXPERT
The Board of Directors of Canadian Natural has determined that Ms. C.M. Best and Mr. W.A. Gobert, each qualify as an “audit committee financial expert” (as defined in paragraph 8(b) of General Instruction B to Form 40-F) serving on its Audit Committee. Ms. C.M. Best, and Mr. W.A. Gobert are, as are all members of the Audit Committee of the Board of Directors of Canadian Natural, “independent” as such term is defined in the rules of the New York Stock Exchange.
CODE OF ETHICS
Canadian Natural has a long-standing Code of Integrity, Business Ethics and Conduct (the “Code of Ethics”), which covers such topics as employment standards, conflict of interest, the treatment of confidential information and trading in Canadian Natural’s shares and is designed to ensure that Canadian Natural’s business is consistently conducted in a legal and ethical manner. Each director and all employees, including each member of senior management and more specifically the principal executive officer, principal financial officer, principal accounting officer or controller and persons performing similar functions, are required to abide by the Code of Ethics. The Nominating, Governance and Risk Committee of the Board of Directors reviews the Code of Ethics annually to ensure it addresses appropriate topics and complies with regulatory requirements and recommends any appropriate changes to the Board for approval.
Any waivers of or amendments to the Code of Ethics must be approved by the Board of Directors and will be appropriately disclosed. In the past fiscal year, there have not been any waivers, including implicit waivers, from any provisions of the Code of Ethics.
The Code of Ethics is available through the System for Electronic Document and Analysis and Retrieval (now referred to as SEDAR+) at www.sedarplus.ca.

4 | Canadian Natural Resources Limited 2023 40-F

P r i n c i p a l D o c u m e n t s E x h i b i t s
Canadian Natural hereby undertakes to provide to any person, without charge and upon request, a copy of its Code of Ethics. Requests for copies can also be made by contacting: Stephanie A. Graham, Corporate Secretary and Associate General Counsel, Canada, Canadian Natural Resources Limited, 2100-855 2nd Street, S.W., Calgary, Alberta, Canada T2P 4J8.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
PricewaterhouseCoopers LLP (“PwC”), Calgary, Alberta, Canada (PCAOB ID 271), has been the auditor of Canadian Natural since 1973. The aggregate amounts billed by PwC for each of the last two fiscal years for audit fees, audit-related fees, tax fees and all other fees, excluding expenses, are set forth below.
Audit Fees
The aggregate fees billed for each of the last two fiscal years of Canadian Natural ended December 31, 2023 and December 31, 2022, for professional services rendered by PwC for the audit of its internal controls and annual consolidated financial statements in connection with statutory and regulatory filings or engagements for those fiscal years, unaudited reviews of the first, second and third quarters of its interim consolidated financial statements and audits of certain of Canadian Natural’s subsidiary companies’ annual financial statements were $2,465,000 for 2023 and were $2,327,000 for 2022.
Audit-Related Fees
The aggregate fees billed for each of the last two fiscal years of Canadian Natural, ended December 31, 2023 and December 31, 2022, for audit-related services by PwC including pension assets, Crown Royalty Statements and greenhouse gas emissions and verification were $1,421,000 for 2023 and were $698,000 for 2022. Canadian Natural’s Audit Committee approved all of these audit-related services. Audit related fees in 2023 included an increase of $700,000 due to performing 2022 GHG emissions and verification procedures in fiscal year 2023 and accelerating the timing of 2023 procedures.
Tax Fees
The aggregate fees billed for each of the last two fiscal years of Canadian Natural, ended December 31, 2023 and December 31, 2022, for professional services rendered by PwC for tax services related to corporate tax return matters were $400,000 for 2023 and were $402,000 for 2022. Canadian Natural’s Audit Committee approved all of these tax-related services.
All Other Fees
The aggregate fees billed for each of the last two fiscal years of Canadian Natural, ended December 31, 2023 and December 31, 2022 for other services were $6,000 for 2023 and were $9,000 for 2022, related to accessing resource materials through PwC’s accounting literature library. Canadian Natural’s Audit Committee approved all of the noted services.
Audit Committee Pre-Approval Policies and Procedures
The Audit Committee’s duties and responsibilities include the review and approval of fees to be paid to the independent auditors, scope and timing of the audit and other related services rendered by the independent auditors. The Audit Committee also reviews and approves the independent auditor’s annual audit plan, including scope, staffing, locations and reliance upon management and internal audit department prior to the commencement of the audit and reviews and approves proposed non-audit services to be provided by the independent auditors, except those non-audit services prohibited by legislation. Canadian Natural did not rely on the de minimis exemption provided by paragraph (c)(7)(i)(c) of Rule 2.01 of Regulation S-X in 2020.
OFF BALANCE SHEET ARRANGEMENTS
The Company does not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on its financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Canadian Natural Resources Limited 2023 40-F | 5

P r i n c i p a l D o c u m e n t s E x h i b i t s
IDENTIFICATION OF THE AUDIT COMMITTEE
Canadian Natural has a separately designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act. The current members of the Audit Committee are Ms. C.M. Best, who chairs the Audit Committee, Messrs. W.A. Gobert, G. D. Giffin, D. A. Tuer and Ms. C.M. Healy.
MINE SAFETY DISCLOSURE
Not Applicable.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
Undertaking
Canadian Natural undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.
Consent to Service of Process
Canadian Natural has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.
Any change to the name or address of the agent for service of process of Canadian Natural shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the registrant.
SIGNATURES
Pursuant to the requirements of the Exchange Act, Canadian Natural certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereto duly authorized.
Dated this 20th da y of March, 2024.

|  |  | CANADIAN NATURAL RESOURCES LIMITED
|  |  | By: | SIGNED "SCOTT G. STAUTH"
|  |  |  | Name: Scott G. Stauth
|  |  |  | Title: President

6 | Canadian Natural Resources Limited 2023 40-F

P r i n c i p a l D o c u m e n t s E x h i b i t s
Documents filed as part of this report:
EXHIBIT INDEX

Exhibit No. | Description
23.1 | Consent of Independent Registered Public Accounting Firm.
23.2 | Consent of Sproule Associates Limited, Independent Petroleum Engineering Consultants.
23.3 | Consent of Sproule International Limited, Independent Petroleum Engineering Consultants.
23.4 | Consent of GLJ Ltd., Independent Petroleum Engineering Consultants.
31.1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
31.2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
32.1 | Certification of Chief Executive Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32.2 | Certification of Chief Financial Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
97.1 | Executive Compensation Recovery Policy
99.1 | Supplementary Oil & Gas Information (Unaudited) for the fiscal year ended December 31, 2023.
101 | Interactive data files with respect to the consolidated financial statements for the fiscal year ended December 31, 2023.

Canadian Natural Resources Limited 2023 40-F | 7